-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, VWY3uevbepZkqXdt3mQ4Bq2gG/El8hVnC5XpW+cxBeVvo77WOZ9x+DcH0pcjVRg/ 0c643/yRt3Z9NsK+jS2r2A== 0000950116-03-003798.txt : 20030905 0000950116-03-003798.hdr.sgml : 20030905 20030905140414 ACCESSION NUMBER: 0000950116-03-003798 CONFORMED SUBMISSION TYPE: S-1/A PUBLIC DOCUMENT COUNT: 5 FILED AS OF DATE: 20030905 FILER: COMPANY DATA: COMPANY CONFORMED NAME: ATLAS AMERICA PUBLIC 12 2003 PROGRAM CENTRAL INDEX KEY: 0001238289 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] FILING VALUES: FORM TYPE: S-1/A SEC ACT: 1933 Act SEC FILE NUMBER: 333-105811 FILM NUMBER: 03883422 BUSINESS ADDRESS: STREET 1: 311 ROUSER RD CITY: MOON TOWNSHIP STATE: PA ZIP: 15108 BUSINESS PHONE: 4122622830 MAIL ADDRESS: STREET 1: 311 ROUSER RD CITY: MOON TOWNSHIP STATE: PA ZIP: 15108 S-1/A 1 s1-a.txt S1-1.TXT As filed with the Securities and Exchange Commission on September 5, 2003 Registration Number 333-105811 - -------------------------------------------------------------------------------- UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 PRE-EFFECTIVE AMENDMENT NO. 2 TO FORM S-1 REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933 ---------- ATLAS AMERICA PUBLIC #12--2003 PROGRAM (Exact name of Registrant as Specified in its Charter) ---------- Delaware (State or other jurisdiction of incorporation or organization) ---------- 1311 (Primary Standard Industrial Classification Code Number) ---------- Not Applicable (IRS Employer Identification Number) ---------- 311 Rouser Road Moon Township, Pennsylvania 15108 (412) 262-2830 (Address, including zip code, and telephone number, including area code, of registrant's principal executive offices) ---------- Jack L. Hollander, Senior Vice President - Direct Participation Programs Atlas Resources, Inc. 311 Rouser Road, Moon Township, Pennsylvania 15108 (412) 262-2830 (Name, address, including zip code, and telephone number, including area code, of agent for service) ---------- With a Copy to: Wallace W. Kunzman, Jr., Esq. Kunzman & Bollinger, Inc. 5100 N. Brookline Suite 600 Oklahoma City, Oklahoma 73112 ---------- As soon as practicable after this Registration Statement becomes effective. (Approximate Date of Commencement of Proposed Sale to the Public) If any of the securities being registered on this form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box: |X| If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. |_| If this Form is a post-effective amendment filed pursuant to rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. |_| If this Form is a post-effective amendment filed pursuant to rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. |_| If delivery of the prospectus is expected to be made pursuant to Rule 434, please check the following box: |_| ---------- CALCULATION OF REGISTRATION FEE
- ----------------------------------------------------------------------------------------------------------------------------------- Proposed Proposed Title of Each Unit Dollar Maximum Maximum Class of Securities Amounts Amounts to be Offering Aggregate Amount of to be Registered to be Registered Registered Price per Unit Offering Price Registration Fee - ----------------------------------------------------------------------------------------------------------------------------------- Investor General Partner Units (1) 7,125 $71,250,000 $10,000 $71,250,000 $6,555 Converted Limited Partner Units (2) 7,125 - 0 - - 0 - - 0 - - 0 - Limited Partner Units (2) 375 $3,750,000 $10,000 $3,750,000 $345 ----- ----------- ------- ----------- ------- TOTAL 7,500 $75,000,000 $75,000,000 $6,900 ===== =========== =========== =======
(1) "Investor General Partner Units" means the investor general partner interests offered to participants in the program. (2) "Limited Partner Units" means up to 375 initial limited partner interests offered to participants in the program and up to 7,125 limited partner units into which the investor general partners automatically will be converted by the managing general partner with no additional price paid by the investor. The Registrant hereby amends this Registration Statement on such dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until this Registration Statement shall become effective on such date as the Commission, acting pursuant to said Section 8(a), may determine. ATLAS AMERICA PUBLIC #12-2003 PROGRAM CROSS REFERENCE SHEET
Item of Form S-1 Caption in Prospectus Item 1. Forepart of the Registration Statement and Outside Front Page of Registration Statement and Outside Front Front Cover Page of Prospectus Cover Page of Prospectus Item 2. Inside Front and Outside Back Cover Pages of Inside Front and Outside Back Cover Pages of Prospectus Prospectus Item 3. Summary Information, Risk Factors and Ratio Of Earnings to Fixed Changes Summary of the Offering; Risk Factors Item 4. Use of Proceeds Capitalization and Source of Funds and Use of Proceeds Item 5. Determination of Offering Price Terms of the Offering The partnerships have not conducted any activities and the managing general partner's officers, directors, promoters and affiliated persons have not acquired any units during the past five years. Also, no units will be issued in this offering to the managing general partner except units subscribed for by the managing general partner, which it does not anticipate. Discounted units, if any, are described in "Plan of Item 6. Dilution Distribution." Item 7. Selling Security Holders The partnerships do not have any selling security holders. Item 8. Plan of Distribution Plan of Distribution Item 9. Description of Securities to be Registered Summary of the Offering; Terms of the Offering; Summary of Partnership Agreement Item 10. Interests of Named Experts and Counsel Legal Opinions; Experts Item 11. Information with respect to the Registrant (a) Description of Business Proposed Activities; Management (b) Description of Property Proposed Activities (c) Legal Proceedings Litigation (d) Market Price of and Dividends on the Registrant's The partnerships have no markets in which their units Common Equity and Related Stockholder Matters are being traded, no holders of units, and they have not conducted any activities or paid any dividends. (e) Financial Statements Financial Information Concerning the Managing General Partner and Atlas America Public #12-2003 Limited Partnership (f) Selected Financial Data The partnerships have not conducted any activities and do not have this information. (g) Supplementary Financial Information The partnerships have not conducted any activities and do not have this information. (h) Management's Discussion and Analysis of Financial Management's Discussion and Analysis of Financial Condition and Results of Operations Condition, Results of Operations, Liquidity and Capital Resources
Item of Form S-1 Caption in Prospectus (i) Changes in and Disagreements with Accountants on There have been no changes in and disagreements with Accounting and Financial Disclosure accountants on accounting and financial disclosure. (j) Quantitative and Qualitative Disclosures about The partnerships have no market for their units and Market Risk none will be created. (k) Directors and Executive Officers Management (l) Executive Compensation Management (m) Security Ownership of Certain Beneficial Owners and Management Management (n) Certain Relationships and Related Transactions Compensation; Management; Conflicts of Interest Item 12. Disclosure of Commission Position on Indemnification Fiduciary Responsibilities of the Managing General for Securities Act Liabilities Partner
PRELIMINARY PROSPECTUS DATED , 2003 ATLAS AMERICA PUBLIC #12-2003 PROGRAM o Up to 7,125 Investor General Partner Units and 7,125 converted Limited Partner Units and up to 375 Limited Partner Units, which are collectively referred to as the "Units", at $10,000 per Unit o $1 Million (100 Units) Minimum Aggregate Subscriptions o $75 Million (7,500 Units) Maximum Aggregate Subscriptions o Atlas America Public #12-2003 Program is a series of up to three limited partnerships which will drill primarily natural gas development wells. They will be managed by Atlas Resources, Inc. of Pittsburgh, Pennsylvania. o If you invest in a partnership, then you will not have any interest in any of the other partnerships unless you also make a separate investment in the other partnerships. o The units will be offered on a "best efforts" "minimum-maximum" basis. This means the broker/dealers must sell at least 100 units and receive subscription proceeds of at least $1 million in order for a partnership to close, and they must use only their best efforts to sell the remaining units in the partnership. o Subscription proceeds for each partnership will be held in an interest bearing escrow account until $1 million has been received. The offering of the partnership designated Atlas America Public #12-2003 Limited Partnership will not extend beyond December 31, 2003, and the offering of any partnership designated Atlas America #12-2004( ) Limited Partnership will not extend beyond December 31, 2004. If subscription proceeds of $1 million are not received by a partnership's offering termination date, then your subscription will be promptly returned to you from the escrow account with interest and without deduction for any fees. o The Offering: In addition to the information in the table below for not less than 95% (7,125) of the units, up to 5% (375) of the units, in the aggregate, may be sold at $8,950 per unit to the managing general partner, its officers, directors and affiliates, and investors who buy units through the officers and directors of the managing general partner; or at $9,300 per unit to registered investment advisors and their clients, and selling agents and their registered representatives and principals. These discounted prices reflect certain fees, sales commissions and reimbursements which will not be paid for these sales. (See "Plan of Distribution.") To the extent that units are sold at discounted prices, a partnership's subscription proceeds will be reduced. (See "Risk Factors - Risks Related to an Investment In a Partnership - Spreading the Risks of Drilling Among a Number of Wells Will be Reduced if Less than the Maximum Subscription Proceeds are Received and Fewer Wells are Drilled.")
Total Total Per Unit Minimum Maximum Public Price $10,000 $1,000,000 $75,000,000 Dealer-manager fee, sales commissions, accountable marketing expense fees, and accountable due diligence reimbursements (1) $ 1,050 $ 105,000 $ 7,875,000 Proceeds to partnership $10,000 $1,000,000 $75,000,000
- --------------- (1) These fees, sales commissions and reimbursements will be paid by the managing general partner as a part of its capital contribution and not from subscription proceeds. o A partnership's drilling operations involve the possibility of a substantial or partial loss of your investment because of wells which are productive, but do not produce enough revenue to return the investment made. o A partnership's revenues are directly related to the ability to market the natural gas and the price of natural gas, which is unstable and cannot be predicted. If the price of gas decreases then your investment return will decrease. o Unlimited joint and several liability for partnership obligations if you choose to invest as an investor general partner until you convert to a limited partner. o Lack of liquidity or a market for the units. o Lack of conflict of interest resolution procedures. o Total reliance on the managing general partner and its affiliates. o Authorization of substantial fees to the managing general partner and its affiliates. o You and the managing general partner will share in costs disproportionately to your sharing of revenues. o Possible allocation of taxable income to you in excess of your cash distributions from your partnership. o No guaranty of cash distributions every quarter. These securities are speculative and are subject to certain risks. You should purchase these securities only if you can afford a complete loss of your investment. (See "Risk Factors", Page 8.) Neither the SEC nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense. Anthem Securities, Inc. - Dealer-Manager Bryan Funding, Inc. - Dealer-Manager in Minnesota and New Hampshire The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted. TABLE OF CONTENTS
SUMMARY OF THE OFFERING 1 Business of the Partnerships and the Managing General Partner 1 Risk Factors 1 Description of Units 2 Investor General Partner Units 3 Limited Partner Units 4 Terms of the Offering 4 Use of Proceeds 5 Subordination, Participation in Costs and Revenues, and Distributions 5 Compensation 7 RISK FACTORS 8 Risks Related To The Partnerships' Oil and Gas Operations 8 No Guarantee of Return of Investment or Rate of Return on Investment Because of Speculative Nature of Drilling Natural Gas and Oil Wells 8 Because Some Wells May Not Return Their Drilling and Completion Costs, It May Take Many Years to Return Your Investment in Cash, If Ever 8 Nonproductive Wells May be Drilled Even Though the Partnerships' Operations are Limited to Development Drilling 8 Partnership Distributions May be Reduced if There is a Decrease in the Price of Natural Gas and Oil 8 Adverse Events in Marketing a Partnership's Natural Gas Could Reduce Partnership Distributions 8 Possible Leasehold Defects 9 Transfer of the Leases Will Not Be Made Until Well is Completed 9 Participation with Third-Parties in Drilling Wells May Require the Partnerships to Pay Additional Costs 9 Risks Related to an Investment In a Partnership 10 If You Choose to Invest as a General Partner, Then You Have Greater Risk Than a Limited Partner 10 The Managing General Partner May Not Meet Its Indemnification and Purchase Obligations If Its Liquid Net Worth Is Not Sufficient 10 An Investment in a Partnership Must be for the Long-Term Because the Units Are Illiquid and Not Readily Transferable 11 Spreading the Risks of Drilling Among a Number of Wells Will be Reduced if Less than the Maximum Subscription Proceeds are Received and Fewer Wells are Drilled 11 The Partnerships Do Not Own Any Prospects, the Managing General Partner Has Complete Discretion to Select Which Prospects Are Acquired By a Partnership, and the Lack of Information for a Portion or Majority of the Prospects Decreases Your Ability to Evaluate the Feasibility of a Partnership 11 Lack of Production Information Increases Your Risk and Decreases Your Ability to Evaluate the Feasibility of a Partnership's Drilling Program 12 The Partnerships Composing This Program and Other Partnerships Sponsored by the Managing General Partner May Compete With Each Other for Prospects, Equipment, Contractors, and Personnel 12 Managing General Partner's Subordination is not a Guarantee of the Return of Any of Your Investment 12 Borrowings by the Managing General Partner Could Reduce Funds Available for Its Subordination Obligation 12 Compensation and Fees to the Managing General Partner Regardless of Success of a Partnership's Activities Will Reduce Cash Distributions 13 The Intended Quarterly Distributions to Investors May be Reduced or Delayed 13 There Are Conflicts of Interest Between the Managing General Partner and the Investors 13 The Presentment Obligation May Not Be Funded and the Presentment Price May Not Reflect Full Value 14 The Managing General Partner May Not Devote the Necessary Time to the Partnerships Because Its Management Obligations Are Not Exclusive 14 Prepaying Subscription Proceeds to Managing General Partner May Expose the Subscription Proceeds to Claims of the Managing General Partner's Creditors 15 Lack of Independent Underwriter May Reduce Due Diligence Investigation of the Partnerships and the Managing General Partner 15 A Lengthy Offering Period May Result in Delays in the Investment of Your Subscription and Any Cash Distributions From the Partnership to You 15 Tax Risks 15 Changes in the Law May Reduce to Some Degree Your Tax Benefits From an Investment in a Partnership 15 You May Owe Taxes in Excess of Your Cash Distributions from a Partnership 15 Your Deduction for Intangible Drilling Costs May Be Limited for Purposes of the Alternative Minimum Tax 16 Investment Interest Deductions of Investor General Partners May Be Limited 16 Lack of Tax Shelter Registration Could Result in Penalties to You 16 ADDITIONAL INFORMATION 16 FORWARD LOOKING STATEMENTS AND ASSOCIATED RISKS 16 INVESTMENT OBJECTIVES 17 ACTIONS TO BE TAKEN BY MANAGING GENERAL PARTNER TO REDUCE RISKS OF ADDITIONAL PAYMENTS BY INVESTOR GENERAL PARTNERS 18
ii TABLE OF CONTENTS
CAPITALIZATION AND SOURCE OF FUNDS AND USE OF PROCEEDS 20 Source of Funds 20 Use of Proceeds 21 COMPENSATION 24 Natural Gas and Oil Revenues 24 Lease Costs 25 Drilling Contracts 25 Per Well Charges 27 Gathering Fees 28 Dealer-Manager Fees 29 Interest and Other Compensation 29 Estimate of Administrative Costs and Direct Costs to be Borne by the Partnerships 30 TERMS OF THE OFFERING 31 Subscription to a Partnership 31 Partnership Closings and Escrow 32 Acceptance of Subscriptions 32 Activation of the Partnerships 33 Suitability Standards 34 In General 34 Purchasers of Limited Partner Units in California, Michigan, New Hampshire, North Carolina, Ohio and Pennsylvania 34 Purchasers of Investor General Partner Units in either: (i) Alabama, Maine, Massachusetts, Minnesota, North Carolina, Ohio, Oklahoma, Pennsylvania, Tennessee, Texas, or Washington; or (ii) Arizona, Indiana, Iowa, Kansas, Kentucky, Michigan, Mississippi, Missouri, New Mexico, Oregon, South Dakota, or Vermont 35 Purchasers of Investor General Partner Units in either California or New Hampshire 36 Fiduciary Accounts and Confirmations 36 PRIOR ACTIVITIES 37 MANAGEMENT 44 Managing General Partner and Operator 44 Officers, Directors and Other Key Personnel 44 Atlas America, Inc., a Delaware Holding Company 48 Organizational Diagram 49 Remuneration 49 Security Ownership of Certain Beneficial Owners 49 Transactions with Management and Affiliates 49 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION, RESULTS OF OPERATIONS, LIQUIDITY AND CAPITAL RESOURCES 50
PROPOSED ACTIVITIES 52 Overview of Drilling Activities 52 Primary Areas of Operations 53 Clinton/Medina Geological Formation In Western Pennsylvania 54 Mississippian/Upper Devonian Sandstone Reservoirs, Fayette County, Pennsylvania 54 Upper Devonian Sandstone Reservoirs, Armstrong County, Pennsylvania 55 Secondary Areas of Operations 55 Clinton/Medina Geological Formation in Western New York 55 Mississippian Berea Sandstone in Eastern Ohio 56 Devonian Oriskany Sandstone in Eastern Ohio 56 Upper Devonian Sandstone in McKean County, Pennsylvania 56 Clinton/Medina Geological Formation in Southern Ohio 57 Acquisition of Leases 57 Deep Drilling Rights Retained by Managing General Partner 58 Interests of Parties 59 Primary Areas 60 Clinton/Medina Geological Formation in Western Pennsylvania and Mississippian/Upper Devonian Sandstone Reservoirs in Fayette and Greene Counties, Pennsylvania 60 Upper Devonian Sandstone Reservoirs in Armstrong County, Pennsylvania 60 Secondary Areas 60 Title to Properties 60 Drilling and Completion Activities; Operation of Producing Wells 61 Sale of Natural Gas and Oil Production 62 Policy of Treating All Wells Equally in a Geographic Area 62 Gathering of Natural Gas 63 Natural Gas Contracts 63 Marketing of Natural Gas Production from Wells in Other Areas of the United States 65 Crude Oil 66 Insurance 66 Use of Consultants and Subcontractors 66 COMPETITION, MARKETS AND REGULATION 66 Natural Gas Regulation 66 Crude Oil Regulation 66 Competition and Markets 67 State Regulations 68 Environmental Regulation 69 Proposed Regulation 69 PARTICIPATION IN COSTS AND REVENUES 70 In General 70 Costs 70 Revenues 71 Subordination of Portion of Managing General Partner's Net Revenue Share 72 Table of Participation in Costs and Revenues 73 Allocation and Adjustment Among Investors 74 Distributions 75 Liquidation 75 CONFLICTS OF INTEREST 76 In General 76 Conflicts Regarding Transactions with the Managing General Partner and its Affiliates 76 Conflict Regarding the Drilling and Operating Agreement 77 Conflicts Regarding Sharing of Costs and Revenues 77 Conflicts Regarding Tax Matters Partner 77 Conflicts Regarding Other Activities of the Managing General Partner, the Operator and Their Affiliates 78 Conflicts Involving the Acquisition of Leases 78 Conflicts Between Investors and the Managing General Partner as an Investor 83
iii TABLE OF CONTENTS
Lack of Independent Underwriter and Due Diligence Investigation 83 Conflicts Concerning Legal Counsel 83 Conflicts Regarding Presentment Feature 84 Conflicts Regarding Managing General Partner Withdrawing an Interest 84 Conflicts Regarding Order of Pipeline Construction and Gathering Fees 84 Procedures to Reduce Conflicts of Interest 84 Policy Regarding Roll-Ups 86 FIDUCIARY RESPONSIBILITY OF THE MANAGING GENERAL PARTNER 87 In General 87 Limitations on Managing General Partner Liability as Fiduciary 88 MATERIAL FEDERAL INCOME TAX CONSEQUENCES 88 Summary of Tax Opinion 88 In General 92 Partnership Classification 92 Limitations on Passive Activities 92 Publicly Traded Partnership Rules 93 Conversion from Investor General Partner to Limited Partner 93 Taxable Year and Method of Accounting 93 2003 and 2004 Expenditures 93 Availability of Certain Deductions 93 Intangible Drilling Costs 94 Drilling Contracts 94 Depletion Allowance 96 Depreciation - Modified Accelerated Cost Recovery System ("MACRS") 97 Lease Acquisition Costs and Abandonment 97 Tax Basis of Units 97 "At Risk" Limitation for Losses 98 Distributions from a Partnership 98 Sale of the Properties 98 Disposition of Units 99 Minimum Tax - Tax Preferences 99 Limitations on Deduction of Investment Interest 100 Allocations 100 Partnership Borrowings 101 Partnership Organization and Offering Costs 101 Tax Elections 101 Disallowance of Deductions under Section 183 of the Internal Revenue Code 101 Termination of a Partnership 102 Lack of Registration as a Tax Shelter 102 Investor Lists 102 Tax Returns and Audits 102 In General 102 Tax Returns 103 Penalties and Interest 103 In General 103 Penalty for Negligence or Disregard of Rules or Regulations 103 Valuation Misstatement Penalty 103 Substantial Understatement Penalty 103 IRS Anti-Abuse Rule and Judicial Doctrines 104 State and Local Taxes 104 Severance and Ad Valorem (Real Estate) Taxes 104 Social Security Benefits and Self-Employment Tax 104 Farmouts 104 Foreign Partners 105 Estate and Gift Taxation 105 Changes in the Law 105
SUMMARY OF PARTNERSHIP AGREEMENT 105 Liability of Limited Partners 105 Amendments 105 Notice 106 Voting Rights 106 Access to Records 107 Withdrawal of Managing General Partner 107 Return of Subscription Proceeds if Funds Are Not Invested in Twelve Months 107 SUMMARY OF DRILLING AND OPERATING AGREEMENT 107 REPORTS TO INVESTORS 108 PRESENTMENT FEATURE 109 TRANSFERABILITY OF UNITS 111 Restrictions on Transfer Imposed by the Securities Laws, the Tax Laws and the Partnership Agreement 111 Conditions to Becoming a Substitute Partner 112 PLAN OF DISTRIBUTION 112 Commissions 112 Indemnification 114 SALES MATERIAL 115 LEGAL OPINIONS 116 EXPERTS 116 LITIGATION 116 FINANCIAL INFORMATION CONCERNING THE MANAGING GENERAL PARTNER AND ATLAS AMERICA PUBLIC #12-2003 LIMITED PARTNERSHIP 116
Exhibits Appendix A Information Regarding Currently Proposed Prospects for Atlas America Public #12-2003 Limited Partnership Exhibit (A) Form of Limited Partnership Agreement of Atlas America Public #12-2003 Limited Partnership [Atlas America Public #12-2004(______) Limited Partnership] Exhibit (I-A) Form of Managing General Partner Signature Page Exhibit (I-B) Form of Subscription Agreement Exhibit (II) Form of Drilling and Operating Agreement for Atlas America Public #12-2003 Limited Partnership [Atlas America Public #12-2004(______) Limited Partnership] Exhibit (B) Special Suitability Requirements and Disclosures to Investors
iv SUMMARY OF THE OFFERING This is a summary and does not include all of the information which may be important to you. You should read the entire prospectus and the attached exhibits and appendix before you decide to invest. Throughout this prospectus when there is a reference to you it is a reference to you as a potential investor or participant in a partnership. Business of the Partnerships and the Managing General Partner Atlas America Public #12-2003 Program, which is sometimes referred to in this prospectus as the "program," consists of up to three Delaware limited partnerships. These limited partnerships are sometimes referred to in this prospectus in the singular as a "partnership" or in the plural as the "partnerships." Units of the various partnerships will be offered and sold in a series during a portion of 2003 and 2004. See "Terms of the Offering" for a discussion of the terms and conditions involved in making an investment in a partnership. Each of the program's partnerships will be a separate business entity from the other partnerships. A limited partnership agreement will govern the rights and obligations of the partners of each partnership. A form of the limited partnership agreement is attached to this prospectus as Exhibit (A). For a summary of the material provisions of the limited partnership agreement which are not covered elsewhere in this prospectus see "Summary of Partnership Agreement." You will be a partner only in the partnership in which you invest. You will have no interest in the business, assets or tax benefits of the other partnerships unless you also invest in the other partnerships. Thus, your investment return will depend solely on the operations and success or lack of success of the partnership in which you invest. Each partnership will drill, own and operate natural gas wells in the Appalachian Basin located in western Pennsylvania, eastern and southern Ohio and western New York as described in "Proposed Activities." Currently, the partnerships do not hold any interests in any properties or prospects on which the wells will be drilled. All offering proceeds will be used to drill development wells. A development well means a well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive. The managing general partner of each partnership will be Atlas Resources, Inc., a Pennsylvania corporation, which was incorporated in 1979, and is sometimes referred to in this prospectus as "Atlas Resources." As set forth in "Prior Activities," the managing general partner has sponsored and serves as managing general partner of 32 private drilling partnerships which raised a total of $174,757,952, and 11 public drilling partnerships which raised a total of $127,440,590. Atlas Resources also will serve as each partnership's general drilling contractor and operator and supervise the drilling, completing and operating of the wells to be drilled. As of January 1, 2003, the managing general partner and its affiliates operated approximately 4,416 natural gas and oil wells located in Ohio, Pennsylvania and New York. The address and telephone number of the partnerships and the managing general partner are 311 Rouser Road, Moon Township, Pennsylvania 15108, (412) 262-2830. Risk Factors This offering involves numerous risks, including the risks related to each partnership's oil and gas operations, the risks related to a partnership investment, and tax risks. You should carefully consider a number of significant risk factors inherent in and affecting the business of a partnership and this offering, including the following. o Each partnership's drilling operations involve the possibility of a substantial or partial loss of your investment because of wells which are productive, but do not produce enough revenue to return the investment made and/or from time to time dry holes. o Each partnership's revenues are directly related to the ability to market the natural gas and the price of natural gas, which cannot be predicted, and if the price of gas decreases then your investment return will decrease. 1 o Unlimited joint and several liability for partnership obligations if you choose to invest as an investor general partner until you convert to a limited partner. o Lack of liquidity or a market for the units, necessitating a long-term commitment. o Total reliance on managing general partner and its affiliates. o Authorization of substantial fees to the managing general partner and its affiliates. o Possible allocation of taxable income to investors in excess of their cash distributions from a partnership. o Each partnership must receive minimum subscriptions of $1 million to close, and the subscription proceeds of all partnerships, in the aggregate, may not exceed $75 million. There are no other requirements regarding the size of a partnership, and the subscription proceeds of one partnership may be substantially more or less than the subscription proceeds of the other partnerships. If only the minimum subscriptions are received in a partnership, then only five wells will be drilled in that partnership which decreases the partnership's ability to spread the risks of drilling. o Certain conflicts of interest between the managing general partner and you and the other investors and lack of procedures to resolve the conflicts. o You and the other investors and the managing general partner will share in costs disproportionately to the sharing of revenues. o Currently, the partnerships do not hold any interests in any properties or prospects on which the wells will be drilled. Although the managing general partner has absolute discretion in determining which properties or prospects will be drilled by a partnership, the managing general partner intends that Atlas America Public #12-2003 Limited Partnership, which must close on or before December 31, 2003, will drill the prospects described in "Appendix A - Information Regarding Currently Proposed Prospects for Atlas America Public #12-2003 Limited Partnership." These prospects represent a portion of the wells to be drilled if the nonbinding targeted maximum subscription proceeds described in "Terms of the Offering - Subscription to a Partnership,, are received. If there are adverse events with respect to any of the currently proposed prospects, the managing general partner will substitute the partnership's prospects. The managing general partner also anticipates that it will designate a portion of each partnership's prospects in the partnerships designated Atlas America Public #12-2004() Limited Partnership by supplement or an amendment to the registration statement. o In each partnership the managing general partner may subordinate a portion of its share of that partnership's net production revenues. This subordination is not a guaranty by the managing general partner, and if the wells in that partnership produce small volumes of gas and/or the price of gas decreases, then even with subordination your cash flow from the partnership may not return your entire investment. o In each partnership quarterly cash distributions to investors may be deferred if revenues are used on partnership operations or reserves. Description of Units In the partnership being offered at the time you subscribe you may buy either: o investor general partner units; or 2 o limited partner units. The first partnership, Atlas America Public #12--2003 Limited Partnership, has been formed as a Delaware limited partnership. However, the other partnerships have not yet been formed. The units offered in those partnerships in 2004 may be preformation investor general partner interests and preformation limited partner interests which will become units of investor general partner interests or limited partner interests, respectively, in the particular partnership if it has not been formed at the time you subscribe. The type of unit you buy will not affect the allocation of costs, revenues, and cash distributions among you and the other investors. There are, however, material differences in the federal income tax effects and liability associated with each type of unit. Investor General Partner Units. o Tax Effect. If you invest in a partnership as an investor general partner, then your share of the partnership's deduction for intangible drilling costs will not be subject to the passive activity limitations because your investor general partner units will not be converted to limited partner units until after all the wells have been drilled and completed. For example, if you pay $10,000 for a unit, then generally you may deduct approximately 90% of your subscription, $9,000, in the year in which you invest, which includes your deduction for intangible drilling costs for all of the wells to be drilled by the partnership. (See "Material Federal Income Tax Consequences - Limitations on Passive Activities.") o Intangible drilling costs generally means those costs of drilling and completing a well that are currently deductible, as compared to lease costs which must be recovered through the depletion allowance and costs for equipment in the well which must be recovered through depreciation deductions. o Liability. If you invest in a partnership as an investor general partner, then you will have unlimited liability regarding the partnership activities. This means if: o the insurance proceeds; o the managing general partner's indemnification; and o the partnership assets were not sufficient to satisfy a partnership liability for which you and the other investor general partners were also liable, then the managing general partner would require you and the other investor general partners to make additional capital contributions to the partnership to satisfy the liability. In addition, you and the other investor general partners have joint and several liability, which means generally that a person with a claim against the partnership may sue all or any one or more of the partnership's general partners, including you, for the entire amount of the liability. (See "Actions To Be Taken By Managing General Partner To Reduce Risks of Additional Payments by Investor General Partners" and "Proposed Activities - Insurance.") Although past performance is no guarantee of future results, the investor general partners in the managing general partner's prior partnerships have not had to make additional capital contributions to their partnerships because of their status as investor general partners. Your investor general partner units in a partnership will be automatically converted by the managing general partner to limited partner units after all of the partnership wells have been drilled and completed. The conversion will not create any tax liability to you or the other investors. 3 Once your units are converted you will have the lesser liability of a limited partner under Delaware law for obligations and liabilities arising after the conversion. However, you will continue to have the responsibilities of a general partner for partnership liabilities and obligations incurred before the effective date of the conversion. For example, you might become liable for partnership liabilities in excess of your subscription during the time the partnership is engaged in drilling activities and for environmental claims that arose during drilling activities, but were not discovered until after conversion. Limited Partner Units. o Tax Effect. If you invest in a partnership as a limited partner, then the use of your share of the partnership's deduction for intangible drilling costs will be limited to net passive income from "passive" trade or business activities. Passive trade or business activities generally include the partnership and other limited partner investments. This means that you will not be able to deduct your share of the partnership's intangible drilling costs in the year in which you invest unless you have passive income from investments other than the partnership. o Liability. If you invest in a partnership as a limited partner, then you will have limited liability. This means you will not be liable for amounts beyond your initial investment and share of undistributed net profits, subject to certain exceptions set forth in "Summary of Partnership Agreement - Liability of Limited Partners." Terms of the Offering The offering period will begin on the date of this prospectus. Each partnership will offer a minimum of 100 units, which is $1 million, and all partnerships, in the aggregate, will offer a maximum of 7,500 units which is $75 million. The maximum subscriptions for each partnership will be lesser of: o the registered amount of $75 million; or o the number of units unsold from the $75 million aggregate registration. The targeted maximum subscription and closing date for each partnership, which are not binding on the managing general partner, are set forth in a table in "Terms of the Offering - Subscription to a Partnership." Units are offered at a subscription price of $10,000 per unit, provided that up to 5% of the units sold, in the aggregate, may be sold to certain investors at discounts as described in "Plan of Distribution." All subscriptions must be paid 100% in cash at the time of subscribing. Your minimum subscription in a partnership is one unit; however, the managing general partner, in its discretion, may accept one-half unit subscriptions from you at any time. Larger fractional subscriptions will be accepted in $1,000 increments, beginning, for example, with either $11,000, $12,000, etc. if you pay $10,000 for a full unit, or $6,000, $7,000, etc. if you pay $5,000 for a one-half unit. You will have the election to purchase units as either an investor general partner or a limited partner as described above in "- Description of Units." Under the partnership agreement no investor, including investor general partners, may participate in the management of a partnership's business. The managing general partner will have exclusive management authority for the partnerships. Subscription proceeds for a partnership will be held in a separate interest bearing escrow account at National City Bank of Pennsylvania until receipt of the minimum subscriptions. Each partnership will be formed as a limited partnership under the Delaware Revised Uniform Limited Partnership Act before breaking escrow. In addition, a partnership may not break escrow as described in "Terms of the Offering - Partnership Closings and Escrow," unless the partnership is in receipt of subscription proceeds of $1 million after the discounts described in "Plan of Distribution." However, on receipt of the minimum subscriptions and written instructions to the escrow agent from the managing general partner and the dealer-manager, the managing general partner on behalf of a partnership may: 4 o break escrow; o transfer the escrowed funds to a partnership account; o enter into the drilling and operating agreement with itself or an affiliate as operator; and o begin drilling to the extent the prospects have been identified in this prospectus or by supplement or an amendment to the registration statement. After breaking escrow additional subscription payments to a partnership may be paid directly to the partnership account for that partnership and will continue to earn interest until the offering closes. (See "Terms of the Offering.") Use of Proceeds Each partnership must receive minimum subscriptions of $1 million to close, and the subscription proceeds of all partnerships, in the aggregate, may not exceed $75 million. There are no other requirements regarding the size of a partnership other than the targeted amounts described in "Terms of the Offering - Subscription to a Partnership" which are not binding on the managing general partner. The subscription proceeds of one partnership may be substantially more or less than the subscription proceeds of the other partnerships. The subscription proceeds of each partnership received from you and the other investors, regardless of whether the minimum or up to the maximum number of units are sold, will be used to pay: o 100% of the intangible drilling costs, which is defined above in "- Description of Units"; and o 34% of the equipment costs of drilling and completing the partnership's wells, but not to exceed 10% of the partnership's subscription proceeds. The managing general partner will contribute all of the leases to each partnership covering the acreage on which each partnership's wells will be drilled and pay: o 66% of the equipment costs of drilling and completing the partnership's wells; and o any equipment costs that exceed 10% of the partnership's subscription proceeds that would otherwise be charged to you and the other investors. The managing general partner also will be charged with 100% of the organization and offering costs for each partnership. A portion of these contributions to each partnership will be in the form of payments to itself, its affiliates and third-parties and the remainder will be in the form of services related to organizing this offering. The managing general partner will receive a credit towards its required capital contribution to each partnership for these payments and services as discussed in "Participation in Costs and Revenues." (See "Capitalization and Source of Funds and Use of Proceeds" and "Material Federal Income Tax Consequences - Intangible Drilling Costs.") Subordination, Participation in Costs and Revenues, and Distributions Each partnership will be a separate business entity from the other partnerships, and you will be a partner only in the partnership in which you invest. You will have no interest in the business, assets or tax benefits of the other partnerships unless you also invest in the other partnerships. Thus, your investment return will depend solely on the operations and success or lack of success of the particular partnership in which you invest. Each partnership is structured to provide you and the other investors with cash distributions equal to a minimum of 10% per unit, based on $10,000 per unit regardless of the actual subscription price for your units, in each of the first five 12-month periods beginning with the partnership's first cash distributions from operations. To help achieve this investment feature the managing general partner will subordinate up to 50% of its share of partnership net production revenues during this subordination period. 5 Each partnership's 60-month subordination period will begin with the partnership's first cash distribution from operations to you and the other investors. However, no subordination distributions to you and the other investors will be required until the partnership's first cash distribution after substantially all of the partnership wells are drilled, completed, and begin producing into a sales line. Subordination distributions will be determined by debiting or crediting current period partnership revenues to the managing general partner as may be necessary to provide the distributions to you and the other investors. At any time during the subordination period, but not after, the managing general partner is entitled to an additional share of partnership revenues to recoup previous subordination distributions to the extent your cash distributions from the partnership exceed the 10% return described above. The specific formula is set forth in Section 5.01(b)(4)(a) of the partnership agreement. The following table sets forth the partnership costs and revenues charged and credited between the managing general partner and you and the other investors for each partnership after deducting from the partnership's gross revenues the landowner royalties and any other lease burdens.
Managing General Partner Investors ------------- ------------- Partnership Costs Organization and offering costs 100% 0% Lease costs 100% 0% Intangible drilling costs 0% 100% Equipment costs (1) 66% 34% Operating costs, administrative costs, direct costs, and all other costs (2) (2) Partnership Revenues Interest income (3) (3) Equipment proceeds (1) 66% 34% All other revenues including production revenues (4)(5) (4)(5)
- --------------- (1) These percentages may vary. If the total equipment costs for all of the partnership's wells that would be charged to you and the other investors exceeds an amount equal to 10% of the subscription proceeds of you and the other investors in the partnership, then the excess will be charged to the managing general partner and equipment proceeds, if any, will be credited in the same percentage in which the equipment costs were charged. (2) These costs will be charged to the parties in the same ratio as the related production revenues are being credited. (3) Interest earned on your subscription proceeds before the final closing of the partnership to which you subscribed will be credited to your account and paid not later than the partnership's first cash distributions from operations. After each closing of a partnership and until the subscription proceeds from the closing are invested in the partnership's natural gas and oil operations any interest income from temporary investments will be allocated pro rata to the investors providing the subscription proceeds. All other interest income, including interest earned on the deposit of operating revenues, will be credited as natural gas and oil production revenues are credited. (4) The managing general partner and the investors in the partnership will share in all of the partnership's other revenues in the same percentage as their respective capital contributions bears to the total partnership capital contributions except that the managing general partner will receive an additional 7% of the partnership revenues. However, the managing general partner's total revenue share may not exceed 35% of partnership revenues. (5) The actual allocation of partnership revenues between the managing general partner and the investors will vary from the allocation described in (4) above if a portion of the managing general partner's partnership net production revenues is subordinated as described above. 6 The managing general partner will review a partnership's accounts at least quarterly to determine whether cash distributions are appropriate and the amount to be distributed, if any. The partnership will distribute funds to you and the other investors that the managing general partner does not believe are necessary for the partnership to retain. (See "Participation in Costs and Revenues.") Compensation The items of compensation paid to the managing general partner and its affiliates from each partnership are as follows: o The managing general partner will receive a share of each partnership's revenues. The managing general partner's revenue share will be in the same percentage as its capital contribution bears to that partnership's total capital contributions plus an additional 7% of partnership revenues, but not to exceed a total of 35% of partnership revenues, regardless of the amount of the managing general partner's capital contribution, subject to the managing general partner's subordination obligation. o The managing general partner will receive a credit to its capital account equal to the cost of the leases or the fair market value of the leases if the managing general partner has reason to believe that cost is materially more than the fair market value. o Each partnership will enter into the drilling and operating agreement with the managing general partner to drill and complete the partnership wells at cost plus 15%. The cost of the well includes reimbursement to the managing general partner of its general and administrative overhead of $14,142 per well. o When the wells for a partnership begin producing the managing general partner, as operator of the wells, will receive: o reimbursement at actual cost for all direct expenses incurred on behalf of the partnership; and o well supervision fees for operating and maintaining the wells during producing operations at a competitive rate. o The managing general partner will receive gathering fees at competitive rates. o Subject to certain exceptions described in "Plan of Distribution," Anthem Securities, Inc., the dealer-manager and an affiliate of the managing general partner, which is sometimes referred to in this prospectus as "Anthem Securities," will receive on each unit sold to an investor a 2.5% dealer-manager fee, a 7% sales commission, a .5% accountable marketing expense fee, and a .5% reimbursement of the selling agents' bona fide accountable due diligence expenses. o The managing general partner or an affiliate will have the right to charge a competitive rate of interest on any loan it may make to or on behalf of a partnership. If the managing general partner provides equipment, supplies, and other services to a partnership, then it may do so at competitive industry rates. o The managing general partner and its affiliates will receive an unaccountable, fixed payment reimbursement for their administrative costs, which has been determined by the managing general partner to be $75 per well per month. The managing general partner may not increase this fee during the term of the partnership. (See "Compensation.") 7 RISK FACTORS An investment in a partnership involves a high degree of risk and is suitable only if you have substantial financial means and no need of liquidity in your investment. Risks Related To The Partnerships' Oil and Gas Operations No Guarantee of Return of Investment or Rate of Return on Investment Because of Speculative Nature of Drilling Natural Gas and Oil Wells. Natural gas and oil exploration is an inherently speculative activity. Before the drilling of a well the managing general partner cannot predict with absolute certainty: o the volume of natural gas and oil recoverable from the well; or o the time it will take to recover the natural gas and oil. You may not recover all of your investment in a partnership, or if you do recover your investment in a partnership you may not receive a rate of return on your investment which is competitive with other types of investment. You will be able to recover your investment only through the partnership's distributions of the sales proceeds from the production of natural gas and oil from productive wells. The quantity of natural gas and oil in a well, which is referred to as its reserves, decreases over time as the natural gas and oil is produced until the well is no longer economical to operate. All of these distributions to you will be considered a return of capital until you have received 100% of your investment. This means that you are not receiving a return on your investment in a partnership, excluding tax benefits, until your total cash distributions from the partnership exceed 100% of your investment. (See "Prior Activities.") Because Some Wells May Not Return Their Drilling and Completion Costs, It May Take Many Years to Return Your Investment in Cash, If Ever. Even if a well is completed in a partnership and produces natural gas and oil in commercial quantities, it may not produce enough natural gas and oil to pay for the costs of drilling and completing the well, even if tax benefits are considered. For example, the managing general partner has formed 43 partnerships since 1985. All the partnerships are continuing to make cash distributions, however, 33 of the 43 partnerships have not yet returned to the investor 100% of his capital contributions without taking tax savings into account. Thus, it may take many years to return your investment in cash, if ever. (See "Prior Activities.") Nonproductive Wells May be Drilled Even Though the Partnerships' Operations are Limited to Development Drilling. Each partnership may drill some wells which are nonproductive and must be plugged and abandoned. If one or more of the partnership's wells are nonproductive, then the partnership's productive wells may not produce enough revenues to offset the loss of investment in the nonproductive wells. (See "Prior Activities.") Partnership Distributions May be Reduced if There is a Decrease in the Price of Natural Gas and Oil. The price at which a partnership's natural gas and oil will be sold cannot be predicted. The price of natural gas and oil will depend on supply and demand factors largely beyond the control of the partnership. For example, the demand for natural gas is usually greater in the winter months because of residential heating requirements than the summer months, and generally results in lower natural gas prices in the summer months than in the winter months. Natural gas and oil prices are volatile, and natural gas and oil prices could decrease in the future. If natural gas and oil prices decrease, then your partnership distributions will decrease accordingly. Also, the price of natural gas and oil may decrease during the first years of production when the wells achieve their greatest level of production. This would have a greater adverse effect on your partnership distributions than price decreases in later years when the wells have a lower level of production. (See "Proposed Activities - Sale of Natural Gas and Oil Production.") Adverse Events in Marketing a Partnership's Natural Gas Could Reduce Partnership Distributions. In addition to the risk of decreased natural gas and oil prices described above, there are risks associated with marketing natural gas which could reduce a partnership's distributions to you and the other investors. These risks are set forth below. 8 o Competition from other natural gas producers and marketers in the Appalachian Basin may make it more difficult to market each partnership's natural gas. o The majority of each partnership's natural gas will be sold under a 10-year agreement which began on April 11, 1999, and provides that the price may be adjusted upward or downward in accordance with the spot market price and market conditions as described in "Proposed Activities - Sale of Natural Gas and Oil Production." The managing general partner anticipates that the remainder of each partnership's natural gas will be sold under similar contracts. Thus, none of the partnerships are guaranteed a specific natural gas price, other than through hedging, and the price for each partnership's natural gas may decrease because of market conditions. o There is a credit risk associated with a natural gas purchaser's ability to pay. Each partnership may not be paid or may experience delays in receiving payment for natural gas that has already been delivered. In accordance with industry practice, a partnership typically will deliver natural gas to a purchaser for a period of up to 60 to 90 days before it receives payment. Thus, it is possible that the partnership may not be paid for natural gas that already has been delivered if the natural gas purchaser fails to pay for any reason, including bankruptcy. This ongoing credit risk also may delay or interrupt the sale of the partnership's natural gas or its negotiation of different terms and arrangements, including possible long-term gas supply agreements, for selling its natural gas to other purchasers. o Partnership revenues may be less the farther the natural gas is transported because of increased transportation costs. o Production from wells drilled in certain areas, such as the wells in Crawford County, Pennsylvania and to a lesser extent, Fayette County, Pennsylvania, may be delayed until construction of the necessary gathering lines and production facilities is completed. (See "Proposed Activities - Sale of Natural Gas and Oil Production.") Possible Leasehold Defects. There may be defects in a partnership's title to its leases. Although the managing general partner will obtain a favorable formal title opinion for the leases before each well is drilled, it will not obtain a division order title opinion after the well is completed. A partnership may experience losses from title defects which arose during drilling that would have been disclosed by a division order title opinion, such as liens that may arise during drilling or transfers made after drilling begins. Also, the managing general partner may use its own judgment in waiving title requirements and will not 0be liable for any failure of title of leases transferred to the partnership. (See "Proposed Activities - Title to Properties." Transfer of the Leases Will Not Be Made Until Well is Completed. Because the leases will not be transferred from the managing general partner to a partnership until the wells are drilled and completed, the transfer could be set aside by a creditor of the managing general partner, or the trustee in the event of the voluntary or involuntary bankruptcy of the managing general partner, if it were determined that the managing general partner received less than a reasonably equivalent value for the leases. In this event, the leases and the wells would revert to the creditors or trustee, and the partnership would either recover nothing or the amount paid for the leases and the cost of drilling the wells. Assigning the leases to a partnership after the wells are drilled and completed, however, will not affect the availability of the tax deductions for intangible drilling costs since the partnership will have an economic interest in the wells under the drilling and operating agreement before the wells are drilled. (See "Proposed Activities - Title to Properties.") Participation with Third-Parties in Drilling Wells May Require the Partnerships to Pay Additional Costs. Third-parties will participate with each partnership in drilling some of the wells. Financial risks exist when the cost of drilling, equipping, completing, and operating wells is shared by more than one person. If a partnership pays its share of the costs, but another interest owner does not pay its share of the costs, then the partnership would have to pay the costs of the defaulting party. In this event, the partnership would receive the defaulting party's revenues from the well, if any, under penalty arrangements set forth in the operating agreement. 9 If the managing general partner is not the actual operator of the well, then there is a risk that the managing general partner cannot supervise the third-party operator closely enough. Also, decisions concerning how the well is operated and expenditures related to the well would be made by the third-party operator, and these decisions may not be in the best interests of the partnerships and you and the other investors. Further, the third-party operator may have financial difficulties and fail to pay for materials or services on the wells it drills or operates, which would cause the partnership to incur extra costs in discharging materialmen's and workmen's liens. The managing general partner may not be the operator of the well if the partnership owns less than a 50% interest in the well, or if the managing general partner acquired the interest in the well from a third-party which required that the third-party be named operator as one of the terms of the acquisition. Risks Related to an Investment In a Partnership If You Choose to Invest as a General Partner, Then You Have Greater Risk Than a Limited Partner. If you invest as an investor general partner for the tax benefits instead of as a limited partner, then under Delaware law you will have unlimited liability for your partnership's activities until converted to limited partner status subject to certain exceptions as described in "Actions To Be Taken by Managing General Partner To Reduce Risks of Additional Payments By Investor General Partners - Conversion of Investor General Partner Units to Limited Partner Units." This could result in you being required to make payments, in addition to your original investment, in amounts that are impossible to predict because of their uncertain nature. Under the terms of the partnership agreement, if you are an investor general partner you agree to pay only your proportionate share of your partnership's obligations and liabilities. This agreement, however, does not eliminate your liability to third-parties if another investor general partner does not pay his proportionate share of your partnership's obligations and liabilities. Also, each partnership will own less than 100% of the interest in some of the wells. If a court holds you and the other third-party owners of the well liable for the development and operation of a well and the third-party well owners do not pay their proportionate share of the costs and liabilities associated with the well, then the partnership and you and the other investor general partners also would be liable for those costs and liabilities. As an investor general partner you may become subject to the following: o contract liability, which is not covered by insurance; o liability for pollution, abuses of the environment, and other environmental damages against which the managing general partner cannot insure because coverage is not available or against which it may elect not to insure because of high premium costs or other reasons; and o liability for drilling hazards which result in property damage, personal injury, or death to third-parties in amounts greater than the insurance coverage. The drilling hazards include, but are not limited to well blowouts, fires, and explosions. If your partnership's insurance proceeds and assets, the managing general partner's indemnification of you and the other investor general partners, and the liability coverage provided by major subcontractors were not sufficient to satisfy the liability, then the managing general partner would call for additional funds from you and the other investor general partners to satisfy the liability. (See "Actions To Be Taken By Managing General Partner To Reduce Risks of Additional Payments by Investor General Partners.") The Managing General Partner May Not Meet Its Indemnification and Purchase Obligations If Its Liquid Net Worth Is Not Sufficient. The managing general partner has made commitments to you and the other investors in each partnership regarding the following: o the payment of the majority of equipment costs and organization and offering costs; o indemnification of the investor general partners for liabilities in excess of their pro rata share of partnership assets; and 10 o purchasing units presented by an investor, although this may be suspended if the managing general partner determines, in its sole discretion, that it does not have the necessary cash flow or cannot borrow funds for this purpose on reasonable terms. A significant financial reversal for the managing general partner could adversely affect its ability to honor these obligations. The managing general partner's net worth is based primarily on the estimated value of its producing natural gas properties and is not available in cash without borrowings or a sale of the properties. Also, if natural gas prices decrease, then the estimated value of the properties and the managing general partner's net worth will be reduced. The managing general partner's net worth may not be sufficient, either currently or in the future, to meet its financial commitments under the partnership agreement. These risks are increased because the managing general partner has made similar financial commitments in 39 other partnerships and will make this same commitment in future partnerships. (See "Financial Information Concerning the Managing General Partner and Atlas America Public #12-2003 Limited Partnership.") An Investment in a Partnership Must be for the Long-Term Because the Units Are Illiquid and Not Readily Transferable. If you invest in a partnership, then you must assume the risks of an illiquid investment. The transferability of the units is limited by the federal securities laws, tax laws, and the partnership agreement. The units cannot be readily liquidated since there is not a readily available market for the sale of the units. Further, the partnerships do not intend to list the units on any exchange. Also, a sale of your units could create adverse tax and economic consequences for you. (See "Material Federal Income Tax Consequences-Disposition of Units" and "Presentment Feature.") Spreading the Risks of Drilling Among a Number of Wells Will be Reduced if Less than the Maximum Subscription Proceeds are Received and Fewer Wells are Drilled. Each partnership must receive minimum subscriptions of $1 million to close, and the subscription proceeds of all partnerships, in the aggregate, may not exceed $75 million. There are no other requirements regarding the size of a partnership other than the nonbinding targeted maximum amounts described in "Terms of the Offering - Subscription to a Partnership," and the subscription proceeds of one partnership may be substantially more or less than the subscription proceeds of another partnership. A partnership with a smaller amount of subscription proceeds will drill fewer wells which decreases the partnership's ability to spread the risks of drilling. For example, the managing general partner anticipates that a partnership will drill approximately 5 wells in which it has a 100% working interest if the minimum subscriptions of $1 million are received. This is compared with 75 wells in which it has a 100% working interest if subscription proceeds of $15 million are received by a partnership. On the other hand, to the extent more than the minimum subscriptions are received by a partnership and the number of wells drilled increases, the partnership's overall investment return may decrease if the managing general partner is unable to find enough suitable wells to be drilled. Also, in a large partnership greater demands will be placed on the managing general partner's management capabilities. Also, there may be cost overruns in drilling and completing the wells because the wells will not be drilled and completed on a turnkey basis for a fixed price, which would shift the risk of loss to the managing general partner as drilling contractor. The majority of the equipment costs of a partnership's wells, including any equipment costs in excess of 10% of the partnership's subscription proceeds, will be paid by the managing general partner. However, all of the intangible drilling costs will be charged to you and the other investors. If there is a cost overrun for the intangible drilling costs of a well or wells, then the managing general partner anticipates that it would use the subscription proceeds, if available, to pay the cost overrun or advance the necessary funds to the partnership. Using subscription proceeds to pay cost overruns will result in a partnership drilling fewer wells. The Partnerships Do Not Own Any Prospects, the Managing General Partner Has Complete Discretion to Select Which Prospects Are Acquired By a Partnership, and The Lack of Information for a Portion or Majority of the Prospects Decreases Your Ability to Evaluate the Feasibility of a Partnership. The partnerships do not currently hold any interests in any prospects on which the wells will be drilled, and the managing general partner has absolute discretion in determining which prospects will be acquired to be drilled. 11 The managing general partner has identified in "Proposed Activities" the general areas where each partnership will drill wells and the managing general partner intends that Atlas America Public #12-2003 Limited Partnership, which must close on or before December 31, 2003, will drill the prospects described in "Appendix A - Information Regarding Currently Proposed Prospects for Atlas America Public #12-2003 Limited Partnership." These prospects represent the wells currently proposed to be drilled if approximately $15 million of subscription proceeds are received, which is a portion of the nonbinding targeted maximum subscription proceeds described in "Terms of the Offering - Subscription to a Partnership." If there are adverse events with respect to any of the currently proposed prospects, the managing general partner will substitute the partnership's prospects. The managing general partner also anticipates that it will designate a portion of each partnership's prospects in the partnerships designated Atlas America Public #12-2004(_____) Limited Partnership by supplement or an amendment to the registration statement. Thus, you do not have any geological or production information to evaluate any additional and/or substituted prospects and wells. Instead, you must rely entirely on the managing general partner to select those prospects and wells. The partnerships do not have the right of first refusal in the selection of prospects from the inventory of the managing general partner and its affiliates, and they may sell their prospects to other partnerships, companies, joint ventures, or other persons at any time. Lack of Production Information Increases Your Risk and Decreases Your Ability to Evaluate the Feasibility of a Partnership's Drilling Program. Production information from surrounding wells in the area is an important indicator in evaluating the economic potential of a proposed well to be drilled. However, the data set forth in "Appendix A - Information Concerning Currently Proposed Wells for Atlas America Public #12-2003 Limited Partnership" for the proposed wells in Pennsylvania may not show all the wells drilled and/or production from those wells because there was a third-party operator and the Pennsylvania Department of Environmental Resources keeps production data confidential for the first five years from the time a well starts producing. If the managing general partner is the operator and no production data is shown it is because the wells are not yet completed, on-line to sell production, or have been producing for only a short period of time. This lack of production information from surrounding wells results in greater uncertainty to you and the other investors. The Partnerships Composing This Program and Other Partnerships Sponsored by the Managing General Partner May Compete With Each Other for Prospects, Equipment, Contractors, and Personnel. One or more partnerships in this program or other partnerships sponsored by the managing general partner may have unexpended capital funds at the same time. Thus, these partnerships may compete for suitable prospects and the availability of equipment, contractors, and the managing general partner's personnel. For example, a partnership previously organized by the managing general partner may still be purchasing prospects when the partnerships composing this program are attempting to purchase prospects. This may make it more difficult to complete the prospect acquisition activities for the partnerships composing this program and may make each partnership less profitable. Managing General Partner's Subordination is not a Guarantee of the Return of Any of Your Investment. If cash distributions from the partnership in which you invest are less than a 10% return for each of the first five 12-month periods beginning with the partnership's first cash distributions from operations, then the managing general partner has agreed to subordinate a portion of its share of the partnership's net production revenues. However, if the wells produce only small natural gas and oil volumes, and/or natural gas and oil prices decrease, then even with subordination you may not receive the 10% return for each of the first five years as described above, or a return of your investment. Also, at any time during the subordination period the managing general partner is entitled to an additional share of partnership revenues to recoup previous subordination distributions to the extent your cash distributions from the partnership exceed the 10% return described above. (See "Participation in Costs and Revenues - Subordination of Portion of the Managing General Partner's Net Revenue Share.") Borrowings by the Managing General Partner Could Reduce Funds Available for Its Subordination Obligation. The managing general partner will pledge with respect to each partnership either its partnership interest and/or an undivided interest in the partnership assets equal to or less than its revenue interest, which will range from 32% to 35% depending on the amount of its capital contribution, to secure borrowings for its own corporate purposes. Under agreements previously 12 entered into, the managing general partner's lenders have required a first lien in the property and will have priority over the managing general partner's subordination obligation under each partnership agreement. Thus, if there was a default to the lender under this pledge arrangement, then this would reduce the amount of each partnership's net production revenues available to the managing general partner for its subordination obligation to you and the other investors. Compensation and Fees to the Managing General Partner Regardless of Success of a Partnership's Activities Will Reduce Cash Distributions. The managing general partner and its affiliates will profit from their services in drilling, completing, and operating each partnership's wells, and will receive the other fees and reimbursement of direct costs described in "Compensation" regardless of the success of the partnership's wells. These fees and direct costs will reduce the amount of cash distributions to you and the other investors. The amount of the fees is subject to the complete discretion of the managing general partner other than the fees must not exceed competitive fees charged by unaffiliated third-parties in the same geographic area engaged in similar businesses and any other restrictions set forth in "Compensation." With respect to direct costs, the managing general partner has sole discretion on behalf of each partnership to select the provider of the services or goods and the provider's compensation as discussed in "Compensation." The Intended Quarterly Distributions to Investors May be Reduced or Delayed. Cash distributions to you and the other investors may not be paid each quarter. Distributions may be reduced or deferred, in the discretion of the managing general partner, to the extent a partnership's revenues are used for any of the following: o repayment of borrowings; o cost overruns; o remedial work to improve a well's producing capability; o direct costs and general and administrative expenses of the partnership; o reserves, including a reserve for the estimated costs of eventually plugging and abandoning the wells; or o indemnification of the managing general partner and its affiliates by the partnership for losses or liabilities incurred in connection with the partnership's activities. (See "Participation in Costs and Revenues - Distributions.") There Are Conflicts of Interest Between the Managing General Partner and the Investors. There are conflicts of interest between you and the managing general partner and its affiliates. These conflicts of interest, which are not otherwise discussed in this "Risk Factors" section, include the following: o the managing general partner has determined the compensation and reimbursement that it and its affiliates will receive in connection with the partnerships without any unaffiliated third-party dealing at arms' length on behalf of the investors; o the managing general partner must monitor and enforce, on behalf of the partnerships, its own compliance with the drilling and operating agreement; o because the managing general partner will receive a percentage of revenues greater than the percentage of costs that it pays, there may be a conflict of interest concerning which wells will be drilled based on the wells' risk and profit potential; o the allocation of all intangible drilling costs to you and the other investors and the majority of the equipment costs to the managing general partner may create a conflict of interest concerning whether to complete a well; 13 o if the managing general partner, as tax matters partner, represents a partnership before the IRS potential conflicts include whether or not to expend partnership funds to contest a proposed adjustment by the IRS, if any, to the amount of your deduction for intangible drilling costs, or the credit to the managing general partner's capital account for contributing the leases to the partnership; o which wells will be drilled by the managing general partner's and its affiliates' other affiliated partnerships or third-party programs in which they serve as driller/operator and which wells will be drilled by the partnerships, and the terms on which the partnerships' leases will be acquired; o the terms on which the managing general partner or affiliated limited partnerships may purchase producing wells from each partnership; o the possible purchase of units by the managing general partner, its officers, directors, and affiliates for a reduced price which would dilute the voting rights of you and the other investors on certain matters; o the representation of the managing general partner and each partnership by the same legal counsel; o the right of Atlas Pipeline Partners to determine the order of priority for constructing gathering lines; o the benefits to Atlas Pipeline Partners of the managing general partner drilling wells that will connect to the gathering system owned by Atlas Pipeline Partners; and o the managing general partner's affiliates' obligation, which does not include the partnerships, to pay the difference between the gathering fees to be paid by each partnership and the greater of $.35 per mcf or 16% of the gross sales price for the gas as described in "Proposed Activities - Sale of Natural Gas and Oil Production - Gathering of Natural Gas." Other than certain guidelines set forth in "Conflicts of Interest," the managing general partner has no established procedures to resolve a conflict of interest. The Presentment Obligation May Not Be Funded and the Presentment Price May Not Reflect Full Value. Subject to certain conditions, beginning with the fifth calendar year after your partnership closes you may present your units to the managing general partner for purchase. However, the managing general partner may determine, in its sole discretion, that it does not have the necessary cash flow or cannot borrow funds for this purpose on reasonable terms. In either event the managing general partner may suspend the presentment feature. This risk is increased because the managing general partner has and will incur similar presentment obligations in other partnerships. Further, the presentment price may not reflect the full value of a partnership's property or your units because of the difficulty in accurately estimating natural gas and oil reserves. The estimates are merely appraisals of value and may not correspond to realizable value. Reservoir engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact way, and the accuracy of the reserve estimate is a function of the quality of the available data and of engineering and geological interpretation and judgment. The presentment price paid for your units and any revenues received by you before the presentment may not be equal to the purchase price of the units. Conversely, because the presentment price is a contractual price it is not reduced by discounts such as minority interests and lack of marketability that generally are used to value partnership interests for tax and other purposes. (See "Presentment Feature.") The Managing General Partner May Not Devote the Necessary Time to the Partnerships Because Its Management Obligations Are Not Exclusive. The managing general partner may not devote the necessary time to the partnerships. The managing general partner and its affiliates will be engaged in other oil and gas activities, including other partnerships and unrelated business ventures for their own account or for the account of others, during the term of the partnerships. (See "Management.") 14 Prepaying Subscription Proceeds to Managing General Partner May Expose the Subscription Proceeds to Claims of the Managing General Partner's Creditors. Under the drilling and operating agreement each partnership will be required to immediately pay the managing general partner the investors' share of the entire estimated price for drilling and completing the partnership's wells. Thus, these funds could be subject to claims of the managing general partner's creditors. (See "Financial Information Concerning the Managing General Partner and Atlas America Public #12-2003 Limited Partnership.") Lack of Independent Underwriter May Reduce Due Diligence Investigation of the Partnerships and the Managing General Partner. There has not been an extensive in-depth "due diligence" investigation of the existing and proposed business activities of the partnerships and the managing general partner that would be provided by independent underwriters. Anthem Securities, which is affiliated with the managing general partner, serves as dealer-manager and will receive reimbursement of accountable due diligence expenses for certain due diligence investigations conducted by the selling agents that will be reallowed to the selling agents. However, its due diligence examination concerning the partnerships cannot be considered to be independent or as comprehensive as an investigation that would be conducted by an independent broker/dealer. (See "Conflicts of Interest.") A Lengthy Offering Period May Result in Delays in the Investment of Your Subscription and Any Cash Distributions From the Partnership to You. Because the offering period for a particular partnership can extend for many months, it is likely that there will be a delay in the investment of your subscription. This may create a delay in the partnership's cash distributions to you which will be paid only after payment of the managing general partner's fees and expenses and only if there is sufficient cash available. See "Terms of the Offering" for a discussion of the procedures involved in the offering and in the formation of a partnership. Tax Risks Changes in the Law May Reduce to Some Degree Your Tax Benefits From an Investment in a Partnership. Your investment in a partnership may be affected by changes in the tax laws. For example, under the Jobs and Growth Tax Relief Reconciliation Act of 2003 the top four federal income tax brackets for individuals have been reduced, including reducing the top bracket to 35% from 38.6%. These changes are retroactive to January 1, 2003, and are scheduled to expire December 31, 2010. The lower federal income tax rates will reduce to some degree the amount of taxes you save by virtue of your share of your partnership's deductions for intangible drilling costs, depletion, and depreciation. Also, the federal income tax rates described above may be changed again in the future. You May Owe Taxes in Excess of Your Cash Distributions from a Partnership. You may become subject to income tax liability for partnership income in excess of the cash you actually receive from a partnership in which you invest. For example: o if the partnership borrows money your share of partnership revenues used to pay principal on the loan will be included in your taxable income from the partnership and will not be deductible; o income from sales of natural gas and oil may be accrued by the partnership in one tax year, although payment is not actually received by the partnership until the next tax year; o taxable income or gain may be allocated to you if there is a deficit in your capital account even though you do not receive a corresponding distribution of partnership revenues; o partnership revenues may be expended by the managing general partner for non-deductible costs or retained to establish a reserve for future estimated costs, including a reserve for the estimated costs of eventually plugging and abandoning the wells; and o the taxable disposition of partnership property or your units may result in income tax liability in excess of cash distributions. 15 Your Deduction for Intangible Drilling Costs May Be Limited for Purposes of the Alternative Minimum Tax. You will be allocated a share of your partnership's deduction for intangible drilling costs. However, under current tax law your alternative minimum taxable income cannot be reduced by more than 40% by the deduction for intangible drilling costs. Also, if you invest as a limited partner you may not have enough passive income to use your share of a partnership's deduction for intangible drilling costs. Investment Interest Deductions of Investor General Partners May Be Limited. An investor general partner's share of a partnership's deduction for intangible drilling costs will reduce his investment income and may adversely affect the deductibility of his investment interest expense, if any. Lack of Tax Shelter Registration Could Result in Penalties to You. The managing general partner has determined that the partnerships are not tax shelters required to register with the IRS. If it is subsequently determined by the IRS or the courts that the partnerships were required to be registered with the IRS as tax shelters, then you would be liable for a $250 penalty for failure to include a tax registration number for your partnership on your tax return, unless this failure was due to reasonable cause. ADDITIONAL INFORMATION The program and the partnerships composing the program currently are not required to file reports with the SEC. However, a registration statement on Form S-1 has been filed on behalf of the program with the SEC. Certain portions of the registration statement have been deleted from this prospectus under SEC rules and regulations. You are urged to refer to the registration statement and exhibits for further information concerning the provisions of certain documents referred to in this prospectus. You may read and copy any materials filed as a part of the registration statement, including the tax opinion included as Exhibit 8, at the SEC's Public Reference Room at 450 Fifth Street, N.W., Washington, D.C. 20549. The SEC maintains an internet world wide web site that contains registration statements, reports, proxy statements, and other information about issuers who file electronically with the SEC, including the program. The address of that site is http://www.sec.gov. Also, you may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. In addition, a copy of the tax opinion may be obtained by you or your advisors from the managing general partner at no cost. The delivery of this prospectus does not imply that its information is correct as of any time after its date. FORWARD LOOKING STATEMENTS AND ASSOCIATED RISKS Statements, other than statements of historical facts, included in this prospectus and its exhibits address activities, events or developments that the managing general partner and the partnerships anticipate will or may occur in the future. For example, the words "believes," "anticipates," and "expects" are intended to identify forward-looking statements. These forward-looking statements include such things as: o investment objectives; o business strategy; o estimated future capital expenditures; o competitive strengths and goals; o references to future success; and o other similar matters. 16 These statements are based on certain assumptions and analyses made by the partnerships and the managing general partner in light of their experience and their perception of historical trends, current conditions, and expected future developments. However, whether actual results will conform with these expectations is subject to a number of risks and uncertainties, many of which are beyond the control of the partnerships, including, but not limited to: o general economic, market, or business conditions; o changes in laws or regulations; o the risk that the wells are productive, but do not produce enough revenue to return the investment made; o the risk that the wells are dry holes; and o uncertainties concerning the price of natural gas and oil. Thus, all of the forward-looking statements made in this prospectus and its exhibits are qualified by these cautionary statements. There can be no assurance that actual results will conform with the managing general partner's and the partnerships' expectations. INVESTMENT OBJECTIVES Each partnership's principal investment objectives are to invest its subscription proceeds in natural gas development wells which will: o Provide quarterly cash distributions to you from the partnership in which you invest until the wells are depleted, historically 20+ years, with a minimum annual cash flow of 10% during the first five years beginning with your partnership's first revenue distribution based on $10,000 per unit for all units sold. These distributions of 10% during the first five years are not guaranteed, but are subject to the managing general partner's subordination obligation. The managing general partner anticipates that investors in a partnership will begin to receive quarterly cash distributions approximately seven months after the offering period for a partnership ends. (See "Participation in Costs and Revenues - Subordination of Portion of Managing General Partner's Net Revenue Share.") The partnerships do not currently hold any interests in any prospects on which the wells will be drilled. The basis for this forward looking statement is a reserve and economic report effective September 30, 2002 which was prepared by Wright & Company, Inc., petroleum consultants, and reviewed by the managing general partner, which evaluated the past history and estimated future production of 1,212 wells drilled to the Clinton/Medina geological formation in western Pennsylvania which is one of the primary drilling areas of each partnership. These wells are owned by the managing general partner and its affiliates and not by the partnerships. Based on data in that report, approximately 1,149 of those wells are expected by the managing general partner to produce more than 20 years. The Clinton/Medina geological formation is also the objective formation in southern Ohio and western New York, which are secondary drilling areas. o Obtain tax deductions from the partnership in which you invest in the year that you invest from intangible drilling costs to offset a portion of your taxable income, subject to the passive activity rules if you invest as a limited partner. For example, if you pay $10,000 for a unit your investment will produce a tax deduction of approximately $9,000 per unit, 90%, against: o ordinary income, or capital gain in some situations, if you invest as an investor general partner in a partnership; and o passive income if you invest as a limited partner in a partnership. 17 Under the Jobs and Growth Tax Relief Reconciliation Act of 2003 (the "2003 Tax Act"), many changes in the federal income tax laws were made, including reducing the top four tax brackets for individual taxpayers from 38.6% to 35%, 35% to 33%, 30% to 28%, and 27% to 25%. These changes are retroactive to January 1, 2003 and are scheduled to expire December 31, 2010. If you are in either the 35% or 33% tax bracket, you will save approximately $3,150 or $2,970, respectively, per $10,000 unit in federal income taxes in the year that you invest. Most states also allow this type of a deduction against the state income tax. If all or a portion of the wells in the partnership in which you invest begin producing in the year in which you invest, then you may be allocated taxable income which will be offset by the intangible drilling cost deduction. o Offset a portion of any taxable income generated by your partnership with tax deductions from percentage depletion, which is 15% in 2003. The percentage depletion rate fluctuates from year to year depending on the price of oil, but under current tax law will not be less than the statutory rate of 15% nor more than 25%. o Obtain tax deductions of the remaining 10% of the initial investment of you and the other investors in your partnership over a seven-year cost recovery period. For example, if you pay $10,000 for a unit, you will receive an additional tax deduction of approximately $1,000 per unit for depreciation of your partnership's equipment costs for the wells. Also, under the 2003 Tax Act, for wells placed in service before January 1, 2005, your partnership will be entitled to accelerate the depreciation allowance based on 50% of its qualified equipment costs to the year its wells are placed in service . Your share of this additional accelerated depreciation deduction will not increase your alternative minimum tax. Attainment of these investment objectives by a partnership will depend on many factors, including the ability of the managing general partner to select suitable wells that will be productive and produce enough revenue to return the investment made. The success of each partnership depends largely on future economic conditions, especially the future price of natural gas which is volatile and may decrease. Also, the extent to which each partnership attains the foregoing investment objectives will be different, because each partnership is a separate business entity which: o generally will drill different wells; o may drill wells situated in different areas; and o will drill a different number of wells depending primarily on the amount of its respective subscription proceeds. There can be no guarantee that the foregoing objectives will be attained. ACTIONS TO BE TAKEN BY MANAGING GENERAL PARTNER TO REDUCE RISKS OF ADDITIONAL PAYMENTS BY INVESTOR GENERAL PARTNERS You may choose to invest in a partnership as an investor general partner so that you can receive an immediate tax deduction against any type of income. To help reduce the risk that you and other investor general partners could be required to make additional payments to the partnership, the managing general partner will take the actions set forth below. o Insurance. The managing general partner will obtain and maintain insurance coverage in amounts and for purposes which would be carried by a reasonable, prudent general contractor and operator in accordance with industry standards. Each partnership will be included as an insured under these general, umbrella, and excess liability policies. In addition, the managing general partner requires all of its subcontractors to certify that they have acceptable insurance coverage for worker's compensation and general, auto, and 18 excess liability coverage. Major subcontractors are required to carry general and auto liability insurance with a minimum of $1 million combined single limit for bodily injury and property damage in any one occurrence or accident. In the event of a loss, the insurance policies of the particular subcontractor at risk would be drawn on before the insurance of the managing general partner or that of the partnership. The managing general partner's current insurance coverage satisfies the following specifications: o worker's compensation insurance in full compliance with the laws of the Commonwealth of Pennsylvania and any other applicable state laws where the wells will be drilled; o commercial general liability: bodily injury and property damage third party liability, including products/completed operations, blow out, cratering, and explosion with limits of $1 million per occurrence/$2 million general aggregate; $1 million products/completed operations aggregate; o underground resources and equipment property damages liability to others with a limit of $1 million; o automobile liability with a $1 million combined single limit; o employer's liability with a $500,000 policy limit; o pollution liability resulting from a "pollution incident," which is defined as the discharge, dispersal, seepage, migration, release or escape of one or more pollutants directly from a well site, with a limit of $1 million for bodily injury and property damage and a limit of $100,000 for clean-up for third-parties, however, coverage does not apply to pollution damage to the well site itself or the property of the insured; o commercial umbrella liability; o commercial primary umbrella limit of $25 million over general liability, automobile liability, and employer's liability and a $10 million sublimit for pollution liability; and o commercial excess liability providing excess limits of $24 million over the $25 million provided in the commercial umbrella, but excluding pollution liability. Because the managing general partner is driller and operator of other partnerships, the insurance available to each partnership could be substantially less if insurance claims are made in the other partnerships. This insurance has deductibles, which would first have to be paid by a partnership, of: o $2,500 per occurrence for bodily injury and property damage; and o $10,000 per pollution incident for pollution damage. The insurance has terms, including exclusions, which are standard for the natural gas and oil industry. On request the managing general partner will provide you or your representative a copy of its insurance policies. The managing general partner will use its best efforts to maintain insurance coverage that meets its current coverage, but may be unsuccessful if the coverage becomes unavailable or too expensive. If you are an investor general partner and there is going to be an adverse material change in a partnership's insurance coverage, which the managing general partner does not anticipate, then the managing general partner must notify you at least 30 days before the effective date of the change. You will have the right to 19 convert your units into limited partner units before the change by giving written notice to the managing general partner. o Conversion of Investor General Partner Units to Limited Partner Units. Your investor general partner units will be automatically converted by the managing general partner to limited partner units after all of the wells in your partnership have been drilled and completed. In each partnership, the managing general partner anticipates that the wells will be placed in service approximately seven months after a partnership closes. Once your units are converted, which is a nontaxable event, you will have the lesser liability of a limited partner in your partnership under Delaware law for obligations and liabilities arising after the conversion. However, you will continue to have the responsibilities of a general partner for partnership liabilities and obligations incurred before the effective date of the conversion. For example, you might become liable for partnership liabilities in excess of your subscription during the time the partnership is engaged in drilling activities and for environmental claims that arose during drilling activities, but were not discovered until after conversion. o Nonrecourse Debt. The partnerships do not anticipate that they will borrow funds. However, if borrowings are required, then the partnerships will be permitted to borrow funds only from the managing general partner or its affiliates without recourse against non-partnership assets. Thus, if there is a default under this loan arrangement you cannot be required to contribute funds to the partnership. Any borrowings by a partnership will be repaid from that partnership's revenues. The amount that may be borrowed at any one time by a partnership may not exceed an amount equal to 5% of the investors' subscriptions in the partnership. However, because you do not bear the risk of repaying these borrowings with non-partnership assets, the borrowings will not increase the extent to which you are allowed to deduct your individual share of partnership losses. o Indemnification. The managing general partner will indemnify you from any liability incurred in connection with your partnership that is in excess of your interest in the partnership's: o undistributed net assets; and o insurance proceeds, if any, from all potential sources. The managing general partner's indemnification obligation, however, will not eliminate your potential liability if the managing general partner's assets are insufficient to satisfy its indemnification obligation. There can be no assurance that the managing general partner's assets, including its liquid assets, will be sufficient to satisfy its indemnification obligation. CAPITALIZATION AND SOURCE OF FUNDS AND USE OF PROCEEDS Source of Funds Each partnership must receive minimum subscriptions of $1 million to close, and the subscription proceeds of all partnerships, in the aggregate, may not exceed $75 million. There are no other requirements regarding the size of a partnership, and the subscription proceeds of one partnership may be substantially more or less than the subscription proceeds of the other partnerships. However, see "Terms of the Offering - Subscription to a Partnership" regarding the targeted nonbinding maximum subscription for each partnership. On completion of an offering for a partnership, the partnership's source of funds will be as follows assuming each unit is sold for $10,000: 20 o the subscription proceeds of you and the other investors, which will be: o $1 million if 100 units are sold; o $75 million if 7,500 units are sold; and o the managing general partner's capital contribution, which includes its credit for organization and offering costs and contributing the leases, which must be at least 25% of all capital contributions, and which it estimates will be: o approximately $345,390 if 100 units are sold; and o approximately $25,904,250 if 7,500 units are sold. Thus, the total amount available to a partnership will be approximately $1,345,390 for the sale of 100 units ranging to approximately $100,904,250 for the sale of 7,500 units. The managing general partner has made the largest single capital contribution in each of its prior partnerships and no individual investor has contributed more, although the total investor contributions in each partnership have exceeded the managing general partner's contribution. The managing general partner expects to make the largest single capital contribution in each of the partnerships as well. Use of Proceeds The subscription proceeds received from you and the other investors for a partnership will be used to pay: o 100% of the intangible drilling costs of drilling and completing the partnership's wells; and o 34% of the equipment costs of drilling and completing the partnership's wells, but not to exceed 10% of the partnership's subscription proceeds. The managing general partner will contribute all of the leases to each partnership covering the acreage on which that partnership's wells will be drilled, and pay: o 66% of the equipment costs of drilling and completing the partnership's wells; and o any equipment costs that exceed 10% of the partnership's subscription proceeds that would otherwise be charged to you and the other investors. The managing general partner also will be charged with 100% of the organization and offering costs for each partnership. A portion of these contributions to each partnership will be in the form of payments to itself, its affiliates and third-parties and the remainder will be in the form of services related to organizing this offering. The managing general partner will receive a credit towards its required capital contribution to each partnership for these payments and services as discussed in "Participation in Costs and Revenues." The following tables present information concerning each partnership's use of the proceeds provided by both you and the other investors and the managing general partner. The tables are based on the managing general partner's required capital contribution of 25% of all capital contributions for each partnership, which includes its credit for organization and offering costs and contributing the leases. The entity receiving the dealer-manager fee, sales commissions, the ..5% accountable marketing expense fee, and the .5% reimbursement for bona fide accountable due diligence expenses will be the dealer-manager, a portion of which will be reallowed to the broker/dealers as discussed in "Plan of Distribution." Subject to the above, the organizational costs will be paid to the managing general partner, its affiliates and various third-parties, and the intangible drilling costs and tangible costs will be paid to the managing general partner as general drilling contractor and operator under the drilling and operating agreement. 21 The tables are presented based on: o the sale of 100 units, which is the minimum number of units for each partnership; o the sale of 4,000 units, which is the targeted nonbinding maximum number of units for Atlas America Public #12-2003 Limited Partnership which is to be closed by December 31, 2003; and o the sale of 7,500 units, which is the maximum number of units, in the aggregate, for all partnerships in the program. Substantially all of the proceeds available to each partnership will be expended for the following purposes and in the following manner:
INVESTOR CAPITAL 100 4,000 7,500 UNITS UNITS UNITS NATURE OF PAYMENT SOLD % (1) SOLD % (1) SOLD % (1) - ----------------- ---- ----- ---- ----- ---- ----- Organization and Offering Expenses Dealer-manager fee, sales commissions, .5% - 0 - - 0 - - 0 - - 0 - - 0 - - 0 - accountable marketing expense fee, and .5% reimbursement for bona fide accountable due diligence expenses Organization costs - 0 - - 0 - - 0 - - 0 - - 0 - - 0 - Amount Available for Investment: Intangible drilling costs (2) $900,000 90% $36,000,000 90% $67,500,000 90% Equipment costs (2) $100,000 10% $4,000,000 10% $7,500,000 10% Leases - 0 - - 0 - - 0 - - 0 - - 0 - - 0 - ----- ----- ----- ----- ----- ----- Total Investor Capital $1,000,000 100% $40,000,000 100% $75,000,000 100% ========== ===== =========== ===== =========== =====
_________________________________ (1) The percentage is based on total investor subscriptions and excludes the managing general partner's capital contribution. (2) The equipment costs will vary depending on the actual cost of drilling and completing the wells, but not less than 90% of the subscription proceeds provided by you and the other investors will be used to pay intangible drilling costs. Equipment costs will be charged 34% to the investors and 66% to the managing general partner, however the investors' share of these costs may not exceed 10% of investor subscriptions as discussed in "Participation in Costs and Revenues." Because the actual costs are not known, for purposes of this section of the prospectus, this table and the following tables assume the maximum amount of investor subscriptions, which is 10%, is used to pay equipment costs in order to avoid the possibility of overstating the amount of currently deductible intangible drilling costs charged to the investors. In contrast, the managing general partner's share of equipment costs in the "- Managing General Partner Capital" and the "- Total Partnership Capital" tables below are based on the managing general partner's estimated equipment costs discussed in "Compensation - Drilling Contracts." Thus, the equipment costs shown in this table and the following tables are not consistent with the equipment costs being charged 34% to the investors, but not to exceed 10% of investor subscriptions, and 66% to the managing general partner as set forth above. Nevertheless, the actual equipment costs incurred by each partnership will be charged 34% to the investors, but not to exceed 10% of investor subscriptions, and 66% to the managing general partner, as described in "Participation in Costs and Revenues." 22
MANAGING GENERAL PARTNER CAPITAL 100 4,000 7,500 UNITS UNITS UNITS NATURE OF PAYMENT SOLD % (1) SOLD % (1) SOLD % (1) - ----------------- ---- ----- ---- ----- ---- ----- Organization and Offering Expenses Dealer-manager fee, sales commissions, .5% $105,000 30.4% $4,200,000 30.4% 7,875,000 30.4% accountable marketing expense fee, and .5% reimbursement for bona fide accountable due diligence expenses (2) Organization costs (2) $45,000 13.0% $1,800,000 13.0% $3,375,000 13.0% Amount Available for Investment: Intangible drilling costs - 0 - - 0 - - 0 - - 0 - - 0 - 0% Equipment costs (3) $168,220 48.7% $6,728,800 48.7% $12,616,500 48.7% Leases (4) $27,170 7.9% $1,086,800 7.9% $2,037,750 7.9% ------- --- ---------- --- ---------- --- Total Managing General Partner Capital $ 345,390 100% $13,815,600 100% $25,904,250 100% ========= === =========== === =========== ===
(1) The percentage is based on the managing general partner's capital contribution and excludes the investors' subscriptions. (2) As discussed in "Participation in Costs and Revenues," if these fees, sales commissions, reimbursements and organization costs exceed 15% of the investors' subscription proceeds in a partnership, then the excess will be charged to the managing general partner, but will not be included as part of its capital contribution. (3) Generally, as described in "Compensation - Drilling Contracts," the managing general partner's share of equipment costs is approximately $33,644 per well and for purposes of this table has been quantified based on the managing general partner's estimate of the number of wells that will be drilled as set forth above which is approximately five wells in which it has a 100% working interest per $1 million of subscriptions. Notwithstanding, these costs will vary depending on the actual costs of drilling and completing the wells. Also, see footnote (2) to the " - Investor Capital" table. (4) Instead of contributing cash for the leases, the managing general partner will assign to each partnership the leases covering the acreage on which the partnership's wells will be drilled. Generally, as described in "Compensation - Lease Costs," the managing general partner's lease cost is approximately $5,434 per prospect and for purposes of this table has been quantified based on the managing general partner's estimate of the number of wells that will be drilled as set forth above which is approximately five wells in which it has a 100% working interest per $1 million of subscriptions. Notwithstanding, the managing general partner's lease costs on a prospect may be significantly higher than $5,434, but the managing general partner's credit for the leases contributed must not exceed its cost, unless the managing general partner has a reason to believe that cost is materially more than fair market value of the property, in which case the managing general partner's credit for its lease contribution must not exceed fair market value. 23 TOTAL PARTNERSHIP CAPITAL
100 4,000 7,500 UNITS UNITS UNITS SOLD % (1) SOLD % (1) SOLD % (1) ---- ----- ---- ----- ---- ----- NATURE OF PAYMENT - ----------------- Organization and Offering Expenses Dealer-manager fee, sales commissions, .5% $105,000 7.8% $4,200,000 7.8% $7,875,000 7.8% nonaccountable marketing expense fee, and ..5% reimbursement for bona fide accountable due diligence expenses (2) Organization costs (2) $45,000 3.3% $1,800,000 3.3% $3,375,000 3.3% Amount Available for Investment: Intangible drilling costs (3) $900,000 67.0% $36,000,000 67.0% $67,500,000 67.0% Equipment costs (3) $ 268,220 19.9% $10,728,800 19.9% 20,116,500 19.9% Leases (4) $ 27,170 2.0% $1,086,800 2.0% $2,037,750 2.0% -------- ---- ---------- ---- ---------- ---- Total Partnership Capital $ 1,345,390 100% $53,815,600 100% $100,904,250 100% =========== ==== =========== ==== ============ ====
________________________________________ (1) The percentage is based on total investor subscriptions and the managing general partner's estimate of its capital contributions. (2) As discussed in "Participation in Costs and Revenues," if these fees, sales commissions, reimbursements and organization costs exceed 15% of the investors' subscription proceeds in a partnership, then the excess will be charged to the managing general partner, but will not be included as part of its capital contribution. (3) Generally, as described in "Compensation - Drilling Contracts" the managing general partner's share of equipment costs is approximately $33,644 per well and for purposes of this table has been quantified based on the managing general partner's estimate of the number of wells that will be drilled as set forth above which is approximately five wells in which it has a 100% working interest per $1 million of subscriptions. Notwithstanding, these costs will vary depending on the actual cost of drilling and completing the wells, but not less than 90% of the subscription proceeds provided by you and the other investors will be used to pay intangible drilling costs. Also, see footnote (2) to the " - Investor Capital" table. (4) Instead of contributing cash for the leases, the managing general partner will assign to each partnership the leases covering the acreage on which the partnership's wells will be drilled. Generally, as described in "Compensation - Lease Costs," the managing general partner's lease cost is approximately $5,434 per prospect and for purposes of the table has been quantified based on the managing general partner's estimate of the number of wells that will be drilled as set forth above which is approximately five wells in which it has a 100% working interest per $1 million of subscriptions. Notwithstanding, the managing general partner's lease costs on a prospect may be significantly higher than $5,434, but the managing general partner's credit for the leases contributed must not exceed its cost, unless the managing general partner has a reason to believe that cost is materially more than fair market value of the property, in which case the managing general partner's credit for its lease contribution must not exceed fair market value. COMPENSATION The items of compensation to be paid to the managing general partner and its affiliates from each partnership are set forth below. Natural Gas and Oil Revenues Subject to the managing general partner's subordination obligation, the investors and the managing general partner will share in each partnership's revenues in the same percentages as their respective capital contributions bear to the total partnership capital contributions for that partnership except that the managing general partner will receive an additional 7% of that partnership's revenues. However, the managing general partner's total revenue share may not exceed 35% of that partnership's revenues regardless of the amount of its capital contribution. For example, if the managing general partner contributes the minimum of 25% of the total partnership capital contributions and the investors contribute 75% of the total partnership capital contributions, then the managing general partner will receive 32% of the partnership revenues and the investors will receive 68% of the partnership revenues. On the other hand, if the 24 managing general partner contributes 30% of the total partnership capital contributions and the investors contribute 70% of the total partnership capital contributions, then the managing general partner will receive 35% of the partnership revenues, not 37%, because its revenue share cannot exceed 35% of partnership revenues, and the investors will receive 65% of partnership revenues. Furthermore, the managing general partner's revenue share from each partnership is subject to its subordination obligation as described in "Partnership Costs and Revenues - Subordination of Portion of the Managing General Partner's Net Revenue Share" and the accompanying tables. For example, if the managing general partner's revenue share is 35% of the partnership revenues, then up to 17.5% of the managing general partner's partnership net revenues could be used for its subordination obligation. Lease Costs Under the partnership agreement the managing general partner will contribute to each partnership all the undeveloped leases necessary to cover each of the partnership's prospects. The managing general partner will receive a credit to its capital account equal to: o the cost of the leases; or o the fair market value of the leases if the managing general partner has reason to believe that cost is materially more than the fair market value. The cost of the leases will include a portion of the managing general partner's reasonable, necessary, and actual expenses for services allocated to a partnership's leases by it using industry guidelines. In the primary areas of interest, the managing general partner's lease cost is approximately $5,434 per prospect assuming a partnership acquires 100% of the working interest in the prospect, although from time to time the managing general partner's lease costs on a prospect may be significantly higher than $5,434. The managing general partner's credit for lease costs will be proportionally reduced to the extent a partnership acquires less than 100% of the working interest in the prospect. In this regard, a working interest generally means an interest in the lease under which the owner of the interest must pay some portion of the cost of development, operation, or maintenance of the well. Assuming all the leases are situated in these areas, the managing general partner estimates that its credit for lease costs will be: o $27,170 if $1 million is received, which is 5 wells in which a partnership has a 100% working interest times $5,434 per prospect; and o $2,037,750 if $75 million is received, which is 375 wells in which a partnership has a 100% working interest times $5,434 per prospect. Drilling a partnership's wells may also provide the managing general partner with offset prospects to be drilled by allowing it to determine at the partnership's expense the value of adjacent acreage in which the partnership would not have any interest. Drilling Contracts Each partnership will enter into the drilling and operating agreement with the managing general partner to drill and complete the partnership wells at cost plus 15%. The managing general partner has determined that this is a competitive rate based on: o information it has concerning drilling rates of third-party drilling companies in the Appalachian Basin; o the estimated costs of non-affiliated persons to drill and equip wells in the Appalachian Basin as reported for 2001 by an independent industry association which surveyed other non-affiliated operators in the area; and o information it has concerning increases in drilling costs in the area since 2001. 25 If this rate subsequently exceeds competitive rates available from other non-affiliated persons in the area engaged in the business of rendering or providing comparable services or equipment, then the rate will be adjusted to the competitive rate. However, the 15% premium may not be increased by the managing general partner during the term of the partnership. The managing general partner expects to subcontract some of the actual drilling and completion of each partnership's wells to third-parties selected by it. However, the managing general partner may not benefit by interpositioning itself between the partnership and the actual provider of drilling contractor services, and may not profit by drilling in contravention of its fiduciary obligations to the partnership. Cost, when used with respect to services, generally means the reasonable, necessary, and actual expense incurred in providing the services, determined in accordance with generally accepted accounting principles. The cost of the well includes reimbursement to the managing general partner of the investors' share of its general and administrative overhead equal to $14,142 per well assuming a 100% working interest in the well. The cost of the well also includes all ordinary costs of drilling, testing and completing the well, which includes the cost of the following for a natural gas well, which will be the classification of the majority of the wells: o a second completion and frac, which means, in general, treating a second potentially productive geological formation in an attempt to enhance the gas production from the well; o installing gathering lines for the natural gas of up to 2,500 feet; and o the necessary facilities for the production of natural gas. The amount of compensation that the managing general partner could earn as a result of these arrangements depends on many factors, including the number of wells drilled. Assuming a 100% working interest in the well, the managing general partner anticipates that the average cost of drilling and completing a partnership's wells, excluding lease costs, will be approximately $233,609 per well, which includes the costs paid by you and the other investors in the approximate amount of $199,965 and the managing general partner in the approximate amount of $33,644. This estimate was based on the average well cost, including "natural" completions, paid to the managing general partner for all wells that it drilled in the Appalachian Basin for its partnerships for the calendar year 2002, all of which included a 15% profit per well. Also, in order to provide a more accurate estimate, the average general and administrative overhead reimbursement of $14,380 per well from the investors in 2002 was reduced to $14,142 per well which is the same amount that the investors in the partnerships will pay. These 2002 wells were drilled by the managing general partner's partnerships in different areas with different drilling and completion costs in each area. Based on this average cost for a 100% working interest in each partnership well, as adjusted for a decrease in the investors' reimbursement of the managing general partner's general and administrative overhead from the 2002 average of $14,380 to $14,142 per gross well, the managing general partner expects that the profit of 15% which it will receive will be approximately $26,083 per well with respect to the intangible drilling costs and the portion of equipment costs paid by you and the other investors. The actual compensation received by the managing general partner as a result of each partnership's drilling operations will vary from these assumptions, but the managing general partner's profit will not in any event exceed 15% of the costs of drilling and completing the wells. Also, to the extent that a partnership acquires less than a 100% working interest in a well, its drilling and completion costs of that well will be proportionately decreased. Subject to the foregoing and based on the investors' share of the average well cost in 2002, the managing general partner estimates that its general and administrative overhead reimbursement of $14,142 and profit of 15% (approximately $26,083), which totals $40,225 per well in which a partnership has a 100% working interest, will be: o $201,125 if $1 million is received, which is 5 wells in which a partnership has a 100% working interest times $40,225; and 26 o $15,084,375 if $75 million is received, which is 375 wells in which a partnership has a 100% working interest times $40,225. The average cost of $233,609 per well in which it has a 100% working interest anticipated by the general partner as discussed above consists of: o intangible drilling costs of approximately $182,633 (78.18%); and o equipment costs of approximately $50,976 (21.82%). In this regard, the managing general partner further anticipates that a partnership's cost of drilling and completing any given well in which it has a 100% working interest in the partnership's primary areas, excluding lease costs, may range from as low as approximately $142,785 to as high as $268,000 or more, depending on the area. Per Well Charges Under the drilling and operating agreement when the wells begin producing the managing general partner, as operator of the wells, will receive the following from each partnership: o reimbursement at actual cost for all direct expenses incurred on behalf of the partnership; and o well supervision fees for operating and maintaining the wells during producing operations at a competitive rate. Currently the competitive rate is $275 per well per month. The well supervision fees will be proportionately reduced to the extent the partnership acquires less than 100% of the working interest in the well, and may be adjusted for inflation annually beginning with the second calendar year after a partnership closes. If the foregoing rates exceed competitive rates available from other non-affiliated persons in the area engaged in the business of providing comparable services or equipment, then the rates will be adjusted to the competitive rate. The managing general partner may not benefit by interpositioning itself between the partnership and the actual provider of operator services. In no event will any consideration received for operator services be duplicative of any consideration or reimbursement received under the partnership agreement. The well supervision fee covers all normal and regularly recurring operating expenses for the production, delivery, and sale of natural gas and oil, such as: o well tending, routine maintenance, and adjustment; o reading meters, recording production, pumping, maintaining appropriate books and records; and o preparing reports to the partnership and to government agencies. The well supervision fees do not include costs and expenses related to: o the purchase of equipment, materials, or third-party services; o brine disposal; and o rebuilding of access roads. These costs will be charged at the invoice cost of the materials purchased or the third-party services performed. The managing general partner estimates that it will receive well supervision fees for a partnership's first 12 months of operation after all of the wells have been placed in production of: 27 o $16,500 if $1 million is received, which is 5 wells in which a partnership has a 100% working interest at $275 per well per month; and o $1,237,500 if $75 million is received, which is 375 wells in which a partnership has a 100% working interest at $275 per well per month. Gathering Fees Under the partnership agreement the managing general partner will be responsible for gathering and transporting the natural gas produced by the partnerships to interstate pipeline systems, local distribution companies, and end-users in the area. The managing general partner anticipates that it will use the gathering system owned by Atlas Pipeline Partners for the majority of the natural gas as described in "Proposed Activities - Sale of Natural Gas and Oil Production - Gathering of Natural Gas." The managing general partner's affiliate, Atlas America, Inc., which is sometimes referred to in this prospectus as "Atlas America," or another affiliate controls and manages the pipeline for Atlas Pipeline Partners. Also, Atlas America and the managing general partner's affiliates, Resource Energy, Inc., sometimes referred to in this prospectus as "Resource Energy," and Viking Resources Corporation, sometimes referred to in this prospectus as "Viking Resources," (the "Resource Entities"), which do not include the partnerships, have an agreement with Atlas Pipeline Partners which provides that generally all of the gas produced by their affiliated partnerships, which includes each partnership composing the program, will be gathered and transported through Atlas Pipeline Partners and that the Resource Entities must pay the greater of $.35 per mcf or 16% of the gross sales price for each mcf transported by these affiliated partnerships. Each partnership will pay a gathering fee directly to the managing general partner at the competitive rates described below. If the gathering system owned by Atlas Pipeline Partners is used by the partnership the managing general partner will apply the gathering fee it receives towards the Resource Entities' agreement with Atlas Pipeline Partners, and if a third-party gathering system is used the managing general partner will pay a portion or all of its gathering fee to the third-party gathering the natural gas. The current rates for gathering fees, which have been determined by the managing general partner for each partnership's primary and secondary drilling areas, are set forth in the chart below. Although the gathering fee paid by each partnership to the managing general partner may be increased by the managing general partner, in its sole discretion, from those set forth in the chart below, the managing general partner may not increase the gathering fees beyond those charged by unaffiliated third-parties in the same geographic area engaged in similar businesses. The gathering fees have not been increased by the managing general partner in several years.
Current Amount of Gathering Fees to be -------------------------------------- Each Partnership's Primary Paid by each Partnership to --------------------------- ---------------------------- and Secondary Drilling Areas Managing General Partner (1) ----------------------------- ---------------------------- Clinton/Medina Geological Formation in Western Pennsylvania in Crawford, Mercer, Lawrence, Warren, and Venango Counties, and Eastern Ohio primarily in Stark, Mahoning, Trumbull and Portage Counties .....................................................................................$.29 per mcf Mississippian/Upper Devonian Sandstone Reservoirs in Fayette and Greene Counties, Pennsylvania.....................................................$.35 per mcf Upper Devonian Sandstone Reservoirs in Armstrong County, Pennsylvania.........................................................................(2) Clinton/Medina Geological Formation in New York...................................................$.35 per mcf Mississippian Berea Sandstone Geological Formation in Columbiana County, Ohio.......................................................................$.35 per mcf Devonian Oriskany Sandstone Geological Formation in Tuscarawas County, Ohio.......................................................................$.35 per mcf Clinton/Medina Geological Formation in Southern Ohio..............................................$.35 per mcf Upper Devonian Sandstone Reservoirs in McKean County, Pennsylvania..............................................................$.70 per mcf (3)
______________________ 28 (1) The gathering fee paid by each partnership must not exceed a competitive rate as determined by the managing general partner, and the managing general partner may increase or decrease the gathering fee to a competitive rate from time to time if conditions in the industry change. (2) Each partnership will use a gathering system provided by a third-party joint venture partner which will not charge the partnership a gathering fee if it markets the gas. If the managing general partner markets the gas for the partnership, then the partnership will pay a gathering fee to the managing general partner equal to that charged by the third-party, which the managing general partner anticipates will be $.20 per mcf. (3) In this area, a partnership will deliver gas into a gathering system a segment of which will be provided by Atlas Pipeline Partners and a segment of which will be provided by a third-party. The third-party will receive fees of $.25 per mcf for transportation and $.10 per mcf for compression. From the fees charged the partnership by the managing general partner, the managing general partner will pay $.35 to the third-party and $.35 to Atlas Pipeline Partners. The actual amount to be paid by a partnership to the managing general partner cannot be quantified because the volume of natural gas that will be produced and transported from the partnership's wells cannot be predicted. Dealer-Manager Fees Subject to certain exceptions described in "Plan of Distribution," Anthem Securities, the dealer-manager and an affiliate of the managing general partner, will receive on each unit sold to an investor: o a 2.5% dealer-manager fee; o a 7% sales commission; o a .5% accountable marketing expense fee; and o a .5% reimbursement of the selling agents' bona fide accountable due diligence expenses. The dealer-manager will receive: o $105,000 if $1 million is received by a partnership; and o $7,875,000 if $75 million is received by the partnerships. All of the reimbursement of the selling agents' bona fide accountable due diligence expenses and generally all of the sales commissions will be reallowed to the selling agents, but only a portion of the accountable marketing expense fee may be allowed to the selling agents. Most of the 2.5% dealer-manager fee will be reallowed to the wholesalers who are associated with the managing general partner and registered through Anthem Securities for subscriptions obtained through their efforts. The dealer-manager will retain any of the compensation which is not reallowed. Anthem Securities is a wholly owned subsidiary of AIC, Inc., which owns 100% of the common stock of the managing general partner. Interest and Other Compensation The managing general partner or an affiliate will have the right to charge a competitive rate of interest on any loan it may make to or on behalf of a partnership. If the managing general partner provides equipment, supplies, and other services to a partnership, then it may do so at competitive industry rates. The managing general partner will determine a competitive rate of interest and competitive industry rates for equipment, supplies and other services by conducting a survey of the interest and/or fees charged by unaffiliated third-parties in the same geographic area engaged in similar businesses. If possible, the managing general partner will contact at least two unaffiliated third-parties, however, the managing general partner will have sole discretion in determining the amount to be charged a partnership. 29 Estimate of Administrative Costs and Direct Costs to be Borne by the Partnerships The managing general partner and its affiliates will receive from each partnership an unaccountable, fixed payment reimbursement for their administrative costs, which has been determined by the managing general partner to be $75 per well per month. It is subject to the following: o it will not be increased in amount during the term of the partnership; o it will be proportionately reduced to the extent the partnership acquires less than 100% of the working interest in the well; o it will be the entire payment to reimburse the managing general partner for the partnership's administrative costs; and o it will not be received for plugged or abandoned wells. The managing general partner estimates that the unaccountable, fixed payment reimbursement for administrative costs allocable to a partnership's first 12 months of operation after all of its wells have been placed into production will not exceed approximately: o $4,500 if $1 million is received, which is 5 wells in which it has a 100% working interest at $75 per well per month; and o $337,500 if $75 million is received, which is 375 wells in which it has a 100% working interest at $75 per well per month. Direct costs will be determined by the managing general partner, in its sole discretion, including the provider of the services or goods and the amount of the provider's compensation. Direct costs will be billed directly to and paid by each partnership to the extent practicable. The anticipated direct costs set forth below for a partnership's first 12 months of operation after all of its wells have been placed into production may vary from the estimates shown for numerous reasons which cannot accurately be predicted. These reasons include: o the number of investors; o the number of wells drilled; o the partnership's degree of success in its activities; o the extent of any production problems; o inflation; and o various other factors involving the administration of the partnership.
Minimum Maximum Subscriptions Subscriptions of $1 million of $75 million (1) Direct Costs ------------- ------------------ External Legal....................................................... $ 6,000 $18,000 Accounting Fees for Audit and Tax Preparation....................... 20,500 94,500 Independent Engineering Reports...................................... 1,500 30,000 ----- ------ TOTAL .......................................................... $28,000 $142,500 ======= ========
______ 30 (1) This assumes three partnerships are formed as described below in "Terms of the Offering - Subscription to a Partnership" and the targeted nonbinding maximum subscriptions of each partnership are received. TERMS OF THE OFFERING Subscription to a Partnership Atlas America Public #12-2003 Program will offer for sale an aggregate of $75 million of units in a series of up to three limited partnerships to be formed under the Delaware Revised Uniform Limited Partnership Act. You may purchase units only if you meet the suitability standards set forth below. The units will be offered for sale over a period which may extend up to December 31, 2004, but may end earlier. The minimum required aggregate subscription proceeds for the offering of units in each partnership will be $1 million after the discounts described in "Plan of Distribution." If this minimum amount of aggregate subscriptions is not received in the offering of units of any partnership by its offering termination date, then the partnership will not be funded, and the escrow agent will promptly return all subscription proceeds for that partnership to the respective subscribers in full with any interest earned on the escrowed funds and without deduction for any fees from the escrowed funds. Set forth below are the targeted maximum subscriptions for each partnership, although these targeted amounts are not mandatory and the managing general partner may determine the maximum subscription for each partnership in its sole discretion. The maximum subscription of any partnership must be the lesser of: o the registered amount of $75 million; or o the number of units unsold from the $75 million aggregate registration. The various partnerships and the subscription period for each will be as set forth below, unless earlier terminated or withdrawn by the managing general partner.
Required Targeted Targeted Offering Partnership Minimum Maximum Ending Termination Name Subscription Subscription(2) Date (1)(2) Date (2) ---- ------------ -------------- ----------- ----------- Atlas America Public #12-2003 $1 million $40 million 12/31/03 12/31/03 The units in the above partnership will be sold only during 2003. Atlas America Public #12-2004(A) $1 million $17.5 million 03/30/04 07/30/04 Atlas America Public #12-2004(B) $1 million $17.5 million 08/31/04 12/31/04
The units in the above partnerships will be sold only during 2004. _______________________________________ (1) The offering of units in subsequent partnerships will not begin until the subscription of units in prior partnerships has reached the minimum subscription or that prior offering has ended. (2) The managing general partner may close the subscription period of any partnership at any time once the partnership is in receipt of subscription proceeds of $1 million. Units are offered at a subscription price of $10,000 per unit, subject to certain exceptions which are described in "Plan of Distribution," and must be paid 100% in cash at the time of subscribing. The subscription price of the units has been arbitrarily determined by the managing general partner because the partnerships do not have any prior operations, assets, earnings, liabilities or present value. Your minimum subscription is one unit; however, the managing general partner, in its discretion, may accept one-half unit ($5,000) subscriptions from you at any time in each partnership. Larger fractional 31 subscriptions will be accepted in $1,000 increments, beginning with either $11,000, $12,000, etc. if you pay $10,000 for a full unit or $6,000, $7,000, etc. if you pay $5,000 for a one-half unit. The managing general partner will have exclusive management authority for each partnership. You will have the election to purchase units in a partnership as either an investor general partner or a limited partner. Each partnership will be a separate business entity from the other partnerships. Thus, as an investor, you will be a partner only in the partnership in which you invest. You will have no interest in the business, assets or tax benefits of the other partnerships unless you also invest in the other partnerships. Your investment return will depend solely on the operations and success or lack of success of the particular partnership in which you invest. Partnership Closings and Escrow Subscription proceeds for each partnership will be held in a separate interest bearing escrow account at National City Bank of Pennsylvania until receipt of the minimum subscriptions. A partnership may not break escrow unless the partnership is in receipt of subscription proceeds of $1 million after the discounts described in "Plan of Distribution." However, on receipt of the minimum subscriptions and written instructions to the escrow agent from the managing general partner and the dealer-manager, the managing general partner on behalf of a partnership may: o break escrow; and o transfer the escrowed funds to a partnership account and begin drilling operations as set forth in "- Activation of the Partnerships," below. At or about the time of the initial closing of a particular partnership, the managing general partner anticipates it will supplement this prospectus to reflect the results of the initial closing of that partnership. If subscriptions for $1 million are not received by the offering termination date of a partnership, then the sums deposited in the escrow account will be promptly returned to you and the other subscribers with interest and without deduction for any fees. In this regard, the latest offering termination date is December 31, 2003, for Atlas America Public #12-2003 Limited Partnership, July 30, 2004 for Atlas America Public #12-2004(A) Limited Partnership, and December 31, 2004, for Atlas America Public #12-2004(B) Limited Partnership. Although the managing general partner and its affiliates may buy up to 10% of the units, they do not currently anticipate purchasing any units. If they do buy units, then those units will not be applied towards the minimum subscriptions required for a partnership to break escrow and begin operations. You will receive interest on your subscription proceeds from the time they are deposited in the escrow account, or the partnership account if you subscribe after the minimum subscriptions have been received and escrow has been broken, until the final closing of the partnership to which you subscribed. The interest will be paid to you not later than that partnership's first cash distribution from operations. During each partnership's escrow period its subscription proceeds will be invested only in institutional investments comprised of or secured by securities of the United States government. After the funds are transferred to the partnership account and before their use in partnership operations, they may be temporarily invested in income producing short-term, highly liquid investments, in which there is appropriate safety of principal, such as U.S. Treasury Bills. If the managing general partner determines that a partnership may be deemed an investment company under the Investment Company Act of 1940, then the investment activity will cease. Subscription proceeds will not be commingled with the funds of the managing general partner or its affiliates, nor will subscription proceeds be subject to their creditors' claims before they are paid to the managing general partner under the drilling and operating agreement. Acceptance of Subscriptions You and the other investors should make your checks for units payable to "Atlas America Public #12-2003 Limited Partnership, Escrow Agent, National City Bank of PA," or "Atlas America Public #12-2004(___) Limited Partnership, Escrow Agent, National City Bank of PA," as appropriate, and give your check to your broker/dealer for submission to the dealer-manager and escrow agent. The managing general partner will place all subscription proceeds of each partnership in 32 an escrow account, or the partnership account if you subscribe after the minimum subscriptions have been received and escrow has been broken, until the final closing of the partnership to which you subscribed. Your execution of the subscription agreement constitutes your offer to buy units in the partnership then being offered and to hold the offer open until either: o your subscription is accepted or rejected by the managing general partner; or o you withdraw your offer. To withdraw your offer, you must give written notice to the managing general partner before your offer is accepted by the managing general partner. Your subscription will be accepted or rejected by the partnership no later than 30 days after its receipt. The managing general partner's acceptance of your subscription is discretionary, and the managing general partner may reject your subscription for any reason without incurring any liability to you for this decision. If your subscription is rejected, then all of your funds will be promptly returned to you together with any interest earned on your subscription proceeds. When you will be admitted to a partnership depends on whether your subscription is accepted before or after breaking escrow. If your subscription is accepted: o before breaking escrow, then you will be admitted to the partnership to which you subscribed not later than 15 days after the release from escrow of the investors' funds to that partnership; and o after breaking escrow, then you will be admitted to the partnership to which you subscribed not later than the last day of the calendar month in which your subscription was accepted by that partnership. Your execution of the subscription agreement and the managing general partner's acceptance also constitutes your: o execution of the partnership agreement and agreement to be bound by its terms as a partner; and o grant of a special power of attorney to the managing general partner to file amended certificates of limited partnership and governmental reports, and perform certain other actions on behalf of you and the other investors. Activation of the Partnerships The managing general partner will organize each partnership under the Delaware Revised Uniform Limited Partnership Act before the initial closing of the partnership and breaking escrow. In this regard, the first partnership in the program, Atlas America Public #12-2003 Limited Partnership, has been formed as a Delaware limited partnership. (See "Financial Information Concerning the Managing General Partner and Atlas America Public #12-2003 Limited Partnership.") However, the other partnerships have not yet been formed. The units offered in those partnerships in 2004 may be preformation investor general partner interests and preformation limited partner interests which will become units of investor general partner interests or limited partner interests, respectively, in the particular partnership if it has not been formed at the time you subscribe. After the initial closing of a partnership and the transfer of the escrowed funds to a partnership account, the managing general partner on behalf of a partnership may: o enter into the drilling and operating agreement with itself or an affiliate as operator; and o begin drilling to the extent the prospects have been identified in this prospectus or by supplement or an amendment to the registration statement. Each partnership will be a separate and distinct business and economic entity from the other partnerships. Thus, you will be a partner only in the partnership in which you specifically invest and you will have no interest in any of the other partnerships 33 unless you also invest in other partnerships. Thus, you must consider and rely solely on the operations and success or lack of success of your own partnership in assessing the quality of your investment. Suitability Standards In General. It is the obligation of persons selling the units to make every reasonable effort to assure that the units are suitable for you based on your investment objectives and financial situation, regardless of your income or net worth. However, you should invest in a partnership only if you are willing to assume the risk of a speculative, illiquid, and long-term investment. Also, subscriptions to a partnership will not be accepted from IRAs, Keogh plans and qualified retirement plans because the partnership's income would be characterized as unrelated business taxable income, which is subject to tax. The decision to accept or reject your subscription will be made by the managing general partner, in its sole discretion, and is final. The managing general partner will not accept your subscription until it has reviewed your apparent qualifications, and the suitability determination must be maintained by the managing general partner during the partnership's term and for at least six years thereafter. Units will be sold to you only if you have: o a minimum net worth of $225,000, exclusive of home, home furnishings, and automobiles; or o a minimum net worth of $60,000, exclusive of home, home furnishings, and automobiles, and had during the last tax year or estimate that you will have during the current tax year "taxable income" as defined in Section 63 of the Internal Revenue Code of at least $60,000 without regard to an investment in the partnership. However, if you are a resident of the states set forth below, then additional suitability requirements apply to you. Purchasers of Limited Partner Units in California, Michigan, New Hampshire, North Carolina, Ohio and Pennsylvania. o If you are a resident of California and you purchase limited partner units, then you must: o have a net worth of not less than $250,000, exclusive of home, home furnishings, and automobiles, and expect to have gross income in the current tax year of $65,000 or more; or o have a net worth of not less than $500,000, exclusive of home, home furnishings, and automobiles; or o have a net worth of not less than $1 million; or o expect to have gross income in the current tax year of not less than $200,000. o If you are a resident of Michigan or North Carolina and you purchase limited partner units, then you must: o have a net worth of not less than $225,000, exclusive of home, home furnishings, and automobiles; or o have a net worth of not less than $60,000, exclusive of home, home furnishings, and automobiles, and estimated current tax year taxable income as defined in Section 63 of the Internal Revenue Code of $60,000 or more without regard to an investment in the partnership. o If you are a resident of New Hampshire and you purchase limited partner units, then you must: 34 o have a net worth of not less than $250,000, exclusive of home, home furnishings, and automobiles; or o have a net worth of not less than $125,000, exclusive of home, home furnishings, and automobiles and $50,000 of taxable income. o In addition, if you are a resident of Michigan, Ohio, or Pennsylvania, then you must not make an investment in the partnership which is in excess of 10% of your net worth, exclusive of home, home furnishings and automobiles. Purchasers of Investor General Partner Units in either: (i) Alabama, Maine, Massachusetts, Minnesota, North Carolina, Ohio, Oklahoma, Pennsylvania, Tennessee, Texas, or Washington; or (ii) Arizona, Indiana, Iowa, Kansas, Kentucky, Michigan, Mississippi, Missouri, New Mexico, Oregon, South Dakota, or Vermont. o If you are a resident of: o Alabama, o North Carolina, o Tennessee, o Maine, o Ohio, o Texas, or o Massachusetts, o Oklahoma, o Washington o Minnesota, o Pennsylvania, and you purchase investor general partner units, then you must: o have an individual or joint net worth with your spouse of $225,000 or more, without regard to the investment in the partnership, exclusive of home, home furnishings, and automobiles, and a combined gross income of $100,000 or more for the current year and for the two previous years; or o have an individual or joint net worth with your spouse in excess of $1 million, inclusive of home, home furnishings, and automobiles; or o have an individual or joint net worth with your spouse in excess of $500,000, exclusive of home, home furnishings, and automobiles; or o have a combined "gross income" as defined in Internal Revenue Code Section 61 in excess of $200,000 in the current year and the two previous years. o In addition, if you are a resident of Ohio or Pennsylvania, then you must not make an investment in the partnership which is in excess of 10% of your net worth, exclusive of home, home furnishings, and automobiles. If you are a resident of: o Arizona, o Kentucky, o New Mexico, o Indiana, o Michigan, o Oregon, o Iowa, o Mississippi, o South Dakota, or o Kansas, o Missouri, o Vermont and you purchase investor general partner units, then you must: 35 o have an individual or joint net worth with your spouse of $225,000 or more, without regard to the investment in the partnership, exclusive of home, home furnishings, and automobiles, and a combined "taxable income" of $60,000 or more for the previous year and expect to have a combined "taxable income" of $60,000 or more for the current year and for the succeeding year; or o have an individual or joint net worth with your spouse in excess of $1 million, inclusive of home, home furnishings, and automobiles; or o have an individual or joint net worth with your spouse in excess of $500,000, exclusive of home, home furnishings, and automobiles; or o have a combined "gross income" as defined in Internal Revenue Code Section 61 in excess of $200,000 in the current year and the two previous years. o In addition, if you are a resident of Iowa or Michigan, then you must not make an investment in the partnership which is in excess of 10% of your net worth, exclusive of home, home furnishings, and automobiles. Purchasers of Investor General Partner Units in either California or New Hampshire. o If you are a resident of California and you purchase investor general partner units, then you must: o have a net worth of not less than $250,000, exclusive of home, home furnishings, and automobiles, and expect to have gross income in the current tax year of $120,000 or more; or o have a net worth of not less than $500,000, exclusive of home, home furnishings, and automobiles; or o have a net worth of not less than $1 million; or o expect to have gross income in the current tax year of not less than $200,000. o If you are a resident of New Hampshire and you purchase investor general partner units, then you must: o have a net worth, exclusive of home, home furnishings, and automobiles, of $250,000; or o have a net worth, exclusive of home, home furnishings, and automobiles, of $125,000 and $50,000 of taxable income. Fiduciary Accounts and Confirmations. If there is a sale of a unit to a fiduciary account, then all the suitability standards set forth above must be met by: o the beneficiary; o the fiduciary account; or o the donor or grantor who directly or indirectly supplies the funds to purchase the units if the donor or grantor is the fiduciary. Generally, you are required to execute your own subscription agreement, and the managing general partner will not accept any subscription agreement that has been executed by someone other than you. The only exception is if you have given 36 someone else the legal power of attorney to sign on your behalf and you meet all of the conditions in this prospectus. Also, the managing general partner will: o not complete a sale of units to you until at least five business days after the date you receive a final prospectus; and o send you a confirmation of purchase. PRIOR ACTIVITIES The following tables reflect certain historical data with respect to 32 private drilling partnerships which raised a total of $174,757,952, and 11 public drilling partnerships which raised a total of $127,440,590, that the managing general partner has sponsored. The tables also reflect certain historical data with respect to 1999 Viking Resources LP, a private drilling program which raised $4,555,210, and is the only drilling program sponsored by Viking Resources after it was acquired by Resource America in August 1999. Information concerning other programs sponsored by Viking Resources before it was acquired by Resource America will be provided to you on written request to the managing general partner. The tables also do not include information concerning wells acquired by Atlas Resources through merger or other form of acquisition. Although past performance is no guarantee of future results, the investor general partners in the managing general partner's prior partnerships have not had to make additional capital contributions to their partnerships because of their status as investor general partners. It should not be assumed that you and the other investors will experience returns, if any, comparable to those experienced by investors in the prior drilling partnerships for several reasons, including, but not limited to, differences in: o partnership terms; o property locations; o partnership size; and o economic considerations. The results of the prior drilling partnerships should be viewed only as a measure of the level of activity and experience of the managing general partner with respect to drilling partnerships. 37 Table 1 sets forth certain sales information of previous development drilling partnerships sponsored by the managing general partner and its affiliates. TABLE 1 EXPERIENCE IN RAISING FUNDS AS OF JULY 15, 2003
Managing Years Number General Date Date of Wells Previous of Investor Partner Total Operations First In Assess- Partnership Investors Capital Capital Capital Began Distributions Production ments ------------------- --------- ----------- ----------- ----------- ---------- ------------- ---------- -------- 1. Atlas L.P. #1 - 1985 19 $ 600,000 $ 114,800 $ 714,800 12/31/85 07/02/86 17.55 -0- 2. A.E. Partners 1986 24 631,250 120,400 751,650 12/31/86 04/02/87 16.55 -0- 3. A.E. Partners 1987 17 721,000 158,269 879,269 12/31/87 04/02/88 15.55 -0- 4. A.E. Partners 1988 21 617,050 135,450 752,500 12/31/88 04/02/89 14.55 -0- 5. A.E. Partners 1989 21 550,000 120,731 670,731 12/31/89 04/02/90 13.55 -0- 6. A.E. Partners 1990 27 887,500 244,622 1,132,122 12/31/90 04/02/91 12.55 -0- 7. A.E. Nineties-10 60 2,200,000 484,380 2,684,380 12/31/90 03/31/91 12.33 -0- 8. A.E. Nineties-11 25 750,000 268,003 1,018,003 09/30/91 01/31/92 11.50 -0- 9. A.E. Partners 1991 26 868,750 318,063 1,186,813 12/31/91 04/02/92 11.33 -0- 10. A.E. Nineties-12 87 2,212,500 791,833 3,004,333 12/31/91 04/30/92 11.25 -0- 11. A.E. Nineties-JV 92 155 4,004,813 1,414,917 5,419,730 10/28/92 04/05/93 10.58 -0- 12. A.E. Partners 1992 21 600,000 176,100 776,100 12/14/92 07/02/93 10.08 -0- 13. A.E. Nineties-Public #1 221 2,988,960 528,934 3,517,894 12/31/92 07/15/93 9.83 -0- 14. A.E. Nineties-1993 Ltd. 125 3,753,937 1,264,183 5,018,120 10/08/93 02/10/94 9.50 -0- 15. A.E. Partners 1993 21 700,000 219,600 919,600 12/31/93 07/02/94 9.25 -0- 16. A.E. Nineties-Public #2 269 3,323,920 587,340 3,911,260 12/31/93 06/15/94 9.00 -0- 17. A.E. Nineties-14 263 9,940,045 3,584,027 13,524,072 08/11/94 01/10/95 8.50 -0- 18. A.E. Partners 1994 23 892,500 231,500 1,124,000 12/31/94 07/02/95 8.25 -0- 19. A.E. Nineties-Public #3 391 5,800,990 928,546 6,729,536 12/31/94 06/05/95 8.25 -0- 20. A.E. Nineties-15 244 10,954,715 3,435,936 14,390,651 09/12/95 02/07/96 7.42 -0- 21. A.E. Partners 1995 23 600,000 244,725 844,725 12/31/95 10/02/96 7.00 -0- 22. A.E. Nineties-Public #4 324 6,991,350 1,287,752 8,279,102 12/31/95 07/08/96 7.25 -0- 23. A.E. Nineties-16 274 10,955,465 1,643,320 12,598,785 07/31/96 01/12/97 6.58 -0- 24. A.E. Partners 1996 21 800,000 367,416 1,167,416 12/31/96 07/02/97 6.25 -0- 25. A.E. Nineties-Public #5 378 7,992,240 1,654,740 9,646,980 12/31/96 06/08/97 6.25 -0- 26. A.E. Nineties-17 217 8,813,488 2,113,947 10,927,435 08/29/97 12/12/97 5.67 -0- 27. A.E. Nineties-Public #6 393 9,901,025 1,950,345 11,851,370 12/31/97 06/08/98 5.25 -0- 28. A.E. Partners 1997 13 506,250 231,050 737,300 12/31/97 07/02/98 5.08 -0- 29. A.E. Nineties-18 225 11,391,673 3,448,751 14,840,424 07/31/98 01/07/99 4.33 -0- 30. A.E. Nineties-Public #7 366 11,988,350 3,812,150 15,800,500 12/31/98 07/10/99 4.00 -0- 31. A.E. Partners 1998 26 1,740,000 756,360 2,496,360 12/31/98 07/02/99 4.00 -0- 32. A.E. Nineties-19 288 15,720,450 4,776,598 20,497,048 09/30/99 01/14/00 3.50 -0- 33. A.E. Nineties-Public #8 380 11,088,975 3,148,181 14,237,156 12/31/99 06/09/00 3.00 -0- 34. A.E. Partners 1999 8 450,000 196,500 646,500 12/31/99 10/02/00 3.00 -0- 35. 1999 Viking Resources LP 131 4,555,210 1,678,038 6,233,248 12/31/99 06/01/00 3.00 -0- 36. Atlas America-Series 20 361 18,809,150 6,297,945 25,107,095 09/30/00 01/30/01 2.75 -0- 37. Atlas America - Public #9 530 14,905,465 5,563,527 20,468,992 12/31/00 07/13/01 2.35 -0- 38. Atlas America - Series 21-A 282 12,510,713 4,535,799 17,046,512 05/15/01 11/16/01 2.10 -0- 39. Atlas America - Series 21-B 360 17,411,825 6,442,761 23,854,586 09/19/01 03/02/02 1.50 -0- 40. Atlas America - Public #10 818 21,281,170 7,227,432 28,508,602 12/31/01 06/20/02 1.25 -0- 41. Atlas America - Series 22 258 10,156,375 3,481,591 13,637,966 05/31/02 11/12/02 .75 -0- 42. Atlas America - Series 23 246 9,644,550 3,214,850 12,859,400 09/30/02 02/18/03 .50 -0- 43. Atlas America - Public #11 1017 31,178,145 10,534,476 41,712,621 12/31/02 07/15/03 .25 -0- 44. Atlas America - Series 24-2003(A) (1) 325 14,363,955 4,949,143 19,313,098 05/31/03 (1) (1) -0-
- --------------- (1) This program closed May 31, 2003, and its first distribution is expected early winter 2003. 38 Table 2 reflects the drilling activity of previous development drilling partnerships sponsored by the managing general partner and its affiliates. All the wells were development wells.You should not assume that the past performance of prior partnerships is indicative of the future results of the partnerships. TABLE 2 WELL STATISTICS - DEVELOPMENT WELLS AS OF JULY 15, 2003
GROSS WELLS (1) NET WELLS (2) ------------------------------------ ------------------------------------ Partnership Oil Gas Dry (3) Oil Gas Dry (3) --------- --------- --------- --------- --------- --------- 1. Atlas L.P. #1 - 1985 0 7 1 0 3.15 0.25 2. A.E. Partners 1986 0 8 0 0 3.50 0.00 3. A.E. Partners 1987 0 9 0 0 4.10 0.00 4. A.E. Partners 1988 0 9 0 0 3.80 0.00 5. A.E. Partners 1989 0 10 0 0 3.30 0.00 6. A.E. Partners 1990 0 12 0 0 5.00 0.00 7. A.E. Nineties-10 0 12 0 0 11.50 0.00 8. A.E. Nineties-11 0 14 0 0 4.30 0.00 9. A.E. Partners 1991 0 12 0 0 4.95 0.00 10. A.E. Nineties-12 0 14 0 0 12.50 0.00 11. A.E. Nineties-JV 92 0 52 0 0 24.44 0.00 12. A.E. Partners 1992 0 7 0 0 3.50 0.00 13. A.E. Nineties-Public #1 0 14 0 0 14.00 0.00 14. A.E. Nineties-1993 Ltd. 0 20 1 0 19.40 1.00 15. A.E. Partners 1993 0 8 0 0 4.00 0.00 16. A.E. Nineties-Public #2 0 16 0 0 15.31 0.00 17. A.E. Nineties-14 0 55 2 0 55.00 2.00 18. A.E. Partners 1994 0 12 0 0 5.00 0.00 19. A.E. Nineties-Public #3 0 27 1 0 26.00 1.00 20. A.E. Nineties-15 0 61 1 0 55.50 1.00 21. A.E. Partners 1995 0 6 0 0 3.00 0.00 22. A.E. Nineties-Public #4 0 31 0 0 30.50 0.00 23. A.E. Nineties-16 0 57 6 0 47.50 4.50 24. A.E. Partners 1996 0 13 0 0 4.84 0.00 25. A.E. Nineties-Public #5 0 36 0 0 35.91 0.00 26. A.E. Nineties-17 0 52 5 0 42.00 4.00 27. A.E. Nineties-Public #6 0 55 0 0 44.45 0.00 28. A.E. Partners 1997 0 6 0 0 2.81 0.00 29. A.E. Nineties-18 0 63 0 0 58.00 0.00 30. A.E. Nineties-Public #7 0 64 0 0 57.50 0.00 31. A.E. Partners 1998 0 19 0 0 9.50 0.00 32. A.E. Nineties-19 0 86 4 0 79.75 4.00 33. A.E. Nineties-Public #8 0 58 0 0 54.66 0.00 34. A.E. Partners 1999 0 5 0 0 2.50 0.00 35. 1999 Viking Resources LP 0 25 2 0 23.00 2.00 36. Atlas America - Series 20 0 106 1 0 100.25 1.00 37. Atlas America - Public #9 0 83 2 0 78.75 2.00 38. Atlas America - Series 21-A 0 67 0 0 61.50 0.00 39. Atlas America - Series 21-B 0 88 1 0 81.50 1.00 40. Atlas America - Public #10 0 104 3 0 100.15 3.00 41. Atlas America - Series 22 0 51 1 0 49.55 1.00 42. Atlas America - Series 23 0 47 1 0 47.00 1.00 43. Atlas America - Public #11 0 167 0 0 160.50 0.00 44. Atlas America-Series 24-2003(A) 0 33 0 0 33.00 0.00 --------- --------- --------- --------- --------- --------- 0 1701 32 0 1486.37 28.75 ========= ========= ========= ========= ========= =========
- --------------- (1) A "gross well" is one in which a partnership owns a leasehold interest. (2) A "net well" equals the actual leasehold interest owned in one gross well divided by one hundred. For example, a 50% leasehold interest in a well is one gross well, but a .50 net well. (3) For purposes of this Table only, a "Dry Hole" means a well which is plugged and abandoned with or without a completion attempt because the operator has determined that it will not be productive of gas and/or oil in commercial quantities. 39 Table 3 provides information concerning the operating results of previous development drilling partnerships sponsored by the managing general partner and its affiliates. You should not assume that the past performance of prior partnerships is indicative of the future results of the partnerships. TABLE 3 INVESTOR OPERATING RESULTS - INCLUDING EXPENSES AS OF JULY 15, 2003
Latest TOTAL COSTS Quarterly ----------------------------------------- Cash Cash Cash on Distribution Investor Distri- Cash Return(4) As of Date Partnership Capital (1) Operating Admin. Direct butions(2(4) of Table 1. Atlas L.P. #1 - 1985 $600,000 $206,362 $42,438 $10,791 $1,465,993 244% $11,799 2. A.E. Partners 1986 631,250 163,415 66,629 9,575 713,797 113% 7,210 3. A.E. Partners 1987 721,000 162,611 57,575 9,493 593,413 82% 4,382 4. A.E. Partners 1988 617,050 134,052 54,431 8,910 536,094 87% 3,742 5. A.E. Partners 1989 550,000 128,948 58,442 8,089 728,952 133% 7,604 6. A.E. Partners 1990 887,500 193,833 82,850 9,792 1,004,459 113% 14,021 7. A.E. Nineties - 10 2,200,000 408,712 80,884 27,791 1,788,178 81% 27,563 8. A.E. Nineties - 11 750,000 156,916 91,864 61,025 1,036,467 138% 9,870 9. A.E. Partners 1991 868,750 173,080 107,394 18,013 1,095,532 126% 14,691 10. A.E. Nineties - 12 2,212,500 416,487 85,106 125,240 1,970,163 89% 24,355 11. A.E. Nineties - JV 92 4,004,813 682,153 142,739 215,744 4,185,304(3) 105% 47,965 12. A.E. Partners 1992 600,000 98,158 53,513 7,921 745,769 124% 9,285 13. A.E. Nineties - Public #1 2,988,960 427,383 89,548 104,195 2,263,753 76% 31,274 14. A.E. Nineties - 1993 Ltd. 3,753,937 500,156 98,726 50,295 2,160,770 57% 15,546 15. A.E. Partners 1993 700,000 126,084 39,375 7,474 895,316 128% 13,352 16. A.E. Nineties - Public #2 3,323,920 420,059 77,732 63,180 2,071,833 62% 32,667 17. A.E. Nineties - 14 9,940,045 1,271,063 246,556 58,286 5,680,209 57% 79,337 18. A.E. Partners 1994 892,500 117,987 46,368 6,762 961,703 108% 16,888 19. A.E. Nineties - Public #3 5,800,990 656,815 128,113 65,325 3,635,938 63% 59,701 20. A.E. Nineties - 15 10,954,715 1,237,161 241,912 43,300 7,035,123 64% 128,114 21. A.E. Partners 1995 600,000 71,625 17,283 5,572 363,002 61% 4,157 22. A.E. Nineties - Public #4 6,991,350 766,379 140,703 57,925 3,056,747 44% 60,304 23. A.E. Nineties - 16 10,955,465 1,049,065 177,926 60,938 4,832,989 44% 146,120 24. A.E. Partners 1996 800,000 96,768 21,995 40,950 474,799 59% 16,004 25. A.E. Nineties - Public #5 7,992,240 725,387 132,410 47,699 3,465,654 43% 80,286 26. A.E. Nineties - 17 8,813,488 767,197 130,838 108,200 4,351,910 49% 161,558 27. A.E. Nineties - Public #6 9,901,025 874,196 145,398 49,047 4,767,287 48% 149,181 28. A.E. Partners 1997 506,250 51,702 11,805 27,693 317,486 63% 13,124 29. A.E. Nineties - 18 11,391,673 949,929 151,191 263,969 4,878,682 43% 215,385 30. A.E. Nineties - Public #7 11,988,350 858,846 124,214 55,367 3,774,899 31% 159,224 31. A.E. Partners 1998 1,740,000 162,297 21,350 43,253 950,481 55% 35,864 32. A.E. Nineties - 19 15,720,450 1,073,796 149,635 12,769 5,114,844 33% 275,816 33. A.E. Nineties - ublic #8 11,088,975 786,199 95,415 56,675 3,758,889 34% 158,340 34. A.E. Partners 1999 450,000 30,153 2,991 3,755 299,487 67% 14,995 35. 1999 Viking Resources LP 4,555,210 758,262 0 146,948 5,462,739 120% 221,517 36. Atlas America - Series 20 18,809,150 1,366,143 142,033 49,547 9,875,634 53% 620,114 37. Atlas America - Public #9 14,905,465 1,083,091 93,387 38,432 5,112,379 34% 468,982 38. Atlas America - Series 21-A 12,510,713 573,054 59,999 7,144 2,782,264 22% 480,665 39. Atlas America - Series 21-B 17,411,825 666,039 66,598 6,969 2,925,736 17% 679,471 40. Atlas America - Public #10 21,281,170 670,662 64,010 25,584 3,535,026 17% 939,708 41. Atlas America - Series 22 (5) 10,156,375 246,313 21,642 4,107 1,344,889 13% 697,530 42. Atlas America - Series 23 (5) 9,644,550 135,606 13,872 4,060 727,045 8% 445,649 43. Atlas America - Public #11 (5) 31,178,145 115,039 14,599 6,342 588,269 2% 588,269 44. Atlas America - Series 24-2003 (A) (5) 14,363,955 0 0 0 0 0% 0
(1) There have been no partnership borrowings other than from the managing general partner. The approximate principal amounts of such borrowings are as follows: o A.E. Nineties-10 - $330,000; o A.E. Nineties-11 - $125,000; and o A.E. Nineties-12 - $365,500. A portion of each partnership's cash distributions was used to repay that partnership's loan. (2) All cash distributions were from the sale of gas, and not sales of properties. (3) A portion of the cash distributions was used to drill three reinvestment wells at a cost of $307,434 in accordance with the terms of the offering. (4) This column reflects total cash distributions beginning with the first production from the program as a percentage of the total amount invested in the program and includes the return of the investors' capital. (5) As of the date of this table there is not twelve months of production and/ or not all wells are drilled or on-line to sell production. 40 Table 3A provides information concerning the operating results of previous development drilling partnerships sponsored by the managing general partner and its affiliates. TABLE 3A MANAGING GENERAL PARTNER OPERATING RESULTS - INCLUDING EXPENSES AS OF JULY 15, 2003
Latest TOTAL COSTS Quarterly ----------------------------------------- Cash Cash Cash on Distribution Managing General Distri- Cash Return As of Date Partnership Partner Capital Operating Admin. Direct butions(1) of Table 1. Atlas L.P. #1 - 1985 $114,800 $39,307 $8,083 $2,055 $277,787 242% $2,248 2. A.E. Partners 1986 120,400 31,127 12,691 1,824 136,290 113% 1,373 3. A.E. Partners 1987 158,269 46,885 16,600 2,737 153,361 97% 1,264 4. A.E. Partners 1988 135,450 43,172 17,529 2,870 138,393 102% 1,205 5. A.E. Partners 1989 120,731 28,306 12,829 1,776 165,645 137% 1,669 6. A.E. Partners 1990 244,622 64,611 0 0 384,428 157% 5,461 7. A.E. Nineties - 10 484,380 136,237 0 0 632,471 131% 10,121 8. A.E. Nineties - 11 268,003 67,250 39,370 21,096 444,435 166% 4,230 9. A.E. Partners 1991 318,063 57,693 0 0 460,552 145% 5,906 10. A.E. Nineties - 12 791,833 178,494 36,474 28,167 844,356 107% 10,438 11. A.E. Nineties - JV 92 1,414,917 335,986 70,304 24,722 1,127,847 80% 23,624 12. A.E. Partners 1992 176,100 32,719 0 0 337,583 192% 3,654 13. A.E. Nineties - Public #1 528,934 134,963 28,278 21,097 660,323 125% 9,876 14. A.E. Nineties - 1993 Ltd. 1,264,183 214,352 42,311 17,973 452,399 36% 6,663 15. A.E. Partners 1993 219,600 42,028 0 0 352,604 161% 4,928 16. A.E. Nineties - Public #2 587,340 132,650 24,547 19,952 465,731 79% 10,316 17. A.E. Nineties - 14 3,584,027 626,046 121,438 21,529 1,612,845 45% 39,077 18. A.E. Partners 1994 231,500 39,329 0 0 365,155 158% 6,357 19. A.E. Nineties - Public #3 928,546 218,938 42,704 21,775 1,150,792 124% 19,900 20. A.E. Nineties - 15 3,435,936 530,212 103,677 18,557 2,073,579 60% 54,906 21. A.E. Partners 1995 244,725 23,875 0 0 129,511 53% 1,792 22. A.E. Nineties - Public #4 1,287,752 255,460 46,901 19,308 825,215 64% 20,101 23. A.E. Nineties - 16 1,643,320 287,324 48,731 11,884 926,633 56% 40,020 24. A.E. Partners 1996 367,416 32,256 0 0 171,387 47% 5,891 25. A.E. Nineties - Public #5 1,654,740 241,796 44,137 15,900 779,368 47% 26,762 26. A.E. Nineties - 17 2,113,947 276,609 47,173 9,666 1,429,747 68% 58,249 27. A.E. Nineties - Public #6 1,950,345 291,399 48,466 16,349 1,491,873 76% 49,727 28. A.E. Partners 1997 231,050 17,234 0 0 110,770 48% 4,797 29. A.E. Nineties - 18 3,448,751 436,829 69,526 8,516 2,100,869 61% 55,199 30. A.E. Nineties - Public #7 3,812,150 385,858 55,806 24,875 871,601 23% 36,383 31. A.E. Partners 1998 756,360 54,099 0 0 325,122 43% 12,732 32. A.E. Nineties - 19 4,776,598 493,789 68,810 5,872 2,197,815 46% 70,687 33. A.E. Nineties - Public #8 3,148,181 321,124 38,972 23,149 1,535,321 49% 64,674 34. A.E. Partners 1999 196,500 10,051 0 0 102,031 52% 5,380 35. 1999 Viking Resources LP 1,678,038 252,754 0 48,983 1,820,913 109% 73,839 36. Atlas America - Series 20 6,297,945 505,286 52,533 18,326 3,652,632 58% 229,357 37. Atlas America - Public #9 5,563,527 442,389 38,144 15,698 2,088,155 38% 162,108 38. Atlas America - Series 21-A 4,535,799 293,026 30,680 3,653 1,422,686 31% 245,784 39. Atlas America - Series 21-B 6,442,761 343,111 34,308 3,590 1,507,197 23% 350,031 40. Atlas America - Public #10 7,227,432 315,607 30,122 12,040 1,663,549 23% 442,218 41. Atlas America - Series 22 (2) 3,481,591 118,758 10,184 1,980 648,427 19% 336,308 42. Atlas America - Series 23 (2) 3,214,850 63,816 6,528 1,911 342,146 11% 209,721 43. Atlas America - Public #11 (2) 10,534,476 54,760 6,870 3,019 280,025 3% 280,025 44. Atlas America - Series 24-2003 (A) (2) 4,949,143 0 0 0 0 0% 0
(1) All cash distributions were from the sale of gas and not sales of properties. (2) As of the date of this table there is not twelve months of production and/ or not all wells are drilled or on-line to sell production. 41 Table 4 sets forth the managing general partner's estimate of the federal tax savings to investors in the managing general partner's prior development drilling partnerships, based on the maximum marginal tax rate in each year, the share of tax deductions as a percentage of their subscriptions, and the aggregate cash distributions. You are urged to consult with your own tax advisors concerning your specific tax situation and should not assume that the past performance of prior partnerships is indicative of the future results of the partnerships. TABLE 4 SUMMARY OF INVESTOR TAX BENEFITS AND CASH DISTRIBUTION RETURNS AS OF JULY 15, 2003
Estimated Federal Tax Savings From (1): ------------------------------------------------ Investor 1st Year Eff 1st Year Depletion Depre- Partnership Capital Tax Deduct (2) Tax Rate I.D.C. Deduct (3) Allowance (3) ciation (3) --------------------------- ----------- -------------- -------- ----------------- ------------- ----------- 1. Atlas L.P. #1 - 1985 $ 600,000 99% 50.0% $ 298,337 $122,842 N/A 2. A.E. Partners 1986 631,250 99% 50.0% 312,889 68,709 N/A 3. A.E. Partners 1987 721,000 99% 38.5% 356,895 51,951 N/A 4. A.E. Partners 1988 617,050 99% 33.0% 244,351 46,994 N/A 5. A.E. Partners 1989 550,000 99% 33.0% 179,685 65,548 N/A 6. A.E. Partners 1990 887,500 99% 33.0% 275,125 90,589 N/A 7. A.E. Nineties - 10 2,200,000 100% 33.0% 726,000 154,628 N/A 8. A.E. Nineties - 11 750,000 100% 31.0% 232,500 95,969 N/A 9. A.E. Partners 1991 868,750 100% 31.0% 269,313 104,866 N/A 10. A.E. Nineties - 12 2,212,500 100% 31.0% 685,875 194,065 N/A 11. A.E. Nineties - JV 92 4,004,813 92.5% 31.0% 1,322,905 334,936 N/A 12. A.E. Partners 1992 600,000 100% 31.0% 186,000 76,004 N/A 13. A.E. Nineties - Public #1 2,988,960 80.5% 36.0% 877,511 209,580 254,729 14. A.E. Nineties - 1993 Ltd. 3,753,937 92.5% 39.6% 1,378,377 201,792 N/A 15. A.E. Partners 1993 700,000 100% 39.6% 273,216 80,972 N/A 16. A.E. Nineties - Public #2 3,323,920 78.7% 39.6% 1,036,343 181,693 279,039 17. A.E. Nineties - 14 9,940,045 95% 39.6% 3,739,445 480,589 N/A 18. A.E. Partners 1994 892,500 100% 39.6% 353,430 75,503 N/A 19. A.E. Nineties - Public #3 5,800,990 76.2% 39.6% 1,752,761 315,531 521,115 20. A.E. Nineties - 15 10,954,715 90.0% 39.6% 3,904,261 561,327 N/A 21. A.E. Partners 1995 600,000 100% 39.6% 237,600 23,910 N/A 22. A.E. Nineties - Public #4 6,991,350 80.0% 39.6% 2,214,860 270,380 516,164 23. A.E. Nineties - 16 10,955,465 86.8% 39.6% 3,361,289 372,289 830,506 24. A.E. Partners 1996 800,000 100% 39.6% 316,800 36,320 N/A 25. A.E. Nineties - Public #5 7,992,240 84.9% 39.6% 2,530,954 274,732 530,055 26. A.E. Nineties - 17 8,813,488 85.2% 39.6% 2,966,366 342,189 366,073 27. A.E. Nineties - Public #6 9,901,025 80.0% 39.6% 3,166,406 384,804 580,064 28. A.E. Partners 1997 506,250 100% 39.6% 200,475 23,946 N/A 29. A.E. Nineties - 18 11,391,673 90.0% 39.6% 4,030,884 241,772 344,797 30. A.E. Nineties - Public #7 11,988,350 85.0% 39.6% 4,043,670 256,717 463,771 31. A.E. Partners 1998 1,740,000 100.0% 39.6% 689,040 70,662 N/A 32. A.E. Nineties - 19 15,720,450 90.0% 39.6% 5,602,767 362,823 361,868 33. A.E. Nineties - Public #8 11,088,975 85.0% 39.6% 3,734,654 279,398 365,056 34. A.E. Partners 1999 450,000 100.0% 39.6% 178,200 17,719 N/A 35. 1999 Viking Resources LP 4,555,210 92.0% 39.6% 1,678,038 374,844 N/A 36. Atlas America - Series 20 18,809,150 90.0% 39.6% 6,712,802 578,697 291,307 37. Atlas America - Public #9 14,905,465 90.0% 39.6% 5,349,744 323,830 N/A 38. Atlas America - Series 21-A 12,510,713 91.0% 39.1% 4,468,617 146,759 136,793 39. Atlas America - Series 21-B 17,411,825 91.0% 39.1% 6,197,907 140,052 161,888 40. Atlas America - Public #10 21,281,170 91.0% 39.1% 7,550,729 196,385 302,134 41. Atlas America - Series 22 (8) 10,156,375 91.0% 38.6% 3,564,312 25,367 133,518 42. Atlas America - Series 23 (8) 9,644,550 91.0% 38.6% 3,404,803 7,487 111,298 43. Atlas America - Public #11 (8) 31,178,145 91.0% 38.6% 11,003,503 0 0 44. Atlas America - Series 24- 2003 (A) (8) 14,363,955 (8) 35.0% 0 0 0 Estimated Federal Tax Savings From (1): -------------- Cumulative Percent Cash Distribution Total Cash. of Cash Dist. Section 29 As of Date Dist. And And Tax Savings Partnership Tax Credit (4) Total of Table (5)(6) Tax Savings (5)(6) to Date (5)(6)(7) --------------------------- -------------- ----------- ----------------- ------------------ ------------------ 1. Atlas L.P. #1 - 1985 $ 55,915 $ 477,094 $1,465,993 $ 1,943,087 324% 2. A.E. Partners 1986 13,507 395,104 713,797 1,108,901 176% 3. A.E. Partners 1987 N/A 408,846 593,413 1,002,258 139% 4. A.E. Partners 1988 N/A 291,345 536,094 827,438 134% 5. A.E. Partners 1989 N/A 245,233 728,952 974,186 177% 6. A.E. Partners 1990 281,660 647,374 1,004,459 1,651,833 186% 7. A.E. Nineties - 10 521,602 1,402,230 1,788,178 3,190,408 145% 8. A.E. Nineties - 11 329,800 658,269 1,036,467 1,694,736 226% 9. A.E. Partners 1991 315,893 690,072 1,095,532 1,785,605 206% 10. A.E. Nineties - 12 617,285 1,497,225 1,970,163 3,467,388 157% 11. A.E. Nineties - JV 92 1,002,109 2,659,950 4,185,304 6,845,253 171% 12. A.E. Partners 1992 224,631 486,635 745,769 1,232,405 205% 13. A.E. Nineties - Public #1 N/A 1,341,820 2,263,753 3,605,573 121% 14. A.E. Nineties - 1993 Ltd. N/A 1,580,169 2,160,770 3,740,939 100% 15. A.E. Partners 1993 N/A 354,188 895,316 1,249,504 179% 16. A.E. Nineties - Public #2 N/A 1,497,075 2,071,833 3,568,908 107% 17. A.E. Nineties - 14 N/A 4,220,034 5,680,209 9,900,243 100% 18. A.E. Partners 1994 N/A 428,933 961,703 1,390,636 156% 19. A.E. Nineties - Public #3 N/A 2,589,407 3,635,938 6,225,346 107% 20. A.E. Nineties - 15 N/A 4,465,588 7,035,123 11,500,711 105% 21. A.E. Partners 1995 N/A 261,510 363,002 624,512 104% 22. A.E. Nineties - Public #4 N/A 3,001,404 3,056,747 6,058,150 87% 23. A.E. Nineties - 16 N/A 4,564,085 4,832,989 9,397,074 86% 24. A.E. Partners 1996 N/A 353,120 474,799 827,920 103% 25. A.E. Nineties - Public #5 N/A 3,335,740 3,465,654 6,801,394 85% 26. A.E. Nineties - 17 N/A 3,674,628 4,351,910 8,026,537 91% 27. A.E. Nineties - Public #6 N/A 4,131,274 4,767,287 8,898,561 90% 28. A.E. Partners 1997 N/A 224,421 317,486 541,908 107% 29. A.E. Nineties - 18 N/A 4,617,452 4,878,682 9,496,134 83% 30. A.E. Nineties - Public #7 N/A 4,764,158 3,774,899 8,539,057 71% 31. A.E. Partners 1998 N/A 759,702 950,481 1,710,183 98% 32. A.E. Nineties - 19 N/A 6,327,458 5,114,844 11,442,302 73% 33. A.E. Nineties - Public #8 N/A 4,379,107 3,758,889 8,137,996 73% 34. A.E. Partners 1999 N/A 195,919 299,487 495,406 110% 35. 1999 Viking Resources LP N/A 2,052,882 5,462,739 7,515,621 165% 36. Atlas America - Series 20 N/A 7,582,806 9,875,634 17,458,440 93% 37. Atlas America - Public #9 N/A 5,673,574 5,112,379 10,785,953 72% 38. Atlas America - Series 21-A N/A 4,752,169 2,782,264 7,534,433 60% 39. Atlas America - Series 21-B N/A 6,499,846 2,925,736 9,425,583 54% 40. Atlas America - Public #10 N/A 8,049,248 3,535,026 11,584,273 54% 41. Atlas America - Series 22 (8) N/A 3,723,197 1,344,889 5,068,086 50% 42. Atlas America - Series 23 (8) N/A 3,523,587 727,045 4,250,632 44% 43. Atlas America - Public #11 (8) N/A 11,003,503 588,269 11,591,772 37% 44. Atlas America - Series 24- 2003 (A) (8) N/A 0 0 0 0%
1. These columns reflect the savings in taxes which would have been paid by an investor, assuming full use of deductions available to the investor. 2. Atlas Resources, Inc. anticipates that approximately 90% of an investor general partner's subscription to a partnership will be deductible in the year in which he invests. 3. The I.D.C. Deductions, Depletion Allowance and MACRS depreciation deductions have been reduced to credit equivalents. 4. The Section 29 tax credit is not available with respect to wells drilled after December 31, 1992. N/A means not applicable. 5. These distributions were all from production revenues. 6. This column reflects total cash distributions beginning with the first production from the program and includes the return of investor's capital. 7. These percentages are calculated by dividing the entry for each partnership in the "Total Cash Dist. And Tax Savings" column by that partnership's entry in the "Investor Capital" column. 8. As of the date of this table there is not twelve months of production and/ or not all wells are drilled or on-line to sell production. 42 Table 5 sets forth payments made to the managing general partner and its affiliates from its previous partnerships. TABLE 5 SUMMARY OF PAYMENTS TO THE MANAGING GENERAL PARTNER AND AFFILIATES FROM PRIOR PARTNERSHIPS AS OF JULY 15, 2003
Leasehold Cumulative Non-recurring Drilling and Cumulative Reimbursement Investor Management Completion Operator's of General Partnership Capital Fee Costs (1) Charges and Administrative Overhead ----------------------------------------- ------------ ------------- ------------- ------------- ------------- 1. Atlas L.P. #1 - 1985 $ 600,000 -0- $ 600,000 $ 245,669 $ 50,522 2. A.E. Partners 1986 631,250 -0- 631,250 194,541 79,321 3. A.E. Partners 1987 721,000 -0- 721,000 209,496 74,176 4. A.E. Partners 1988 617,050 -0- 617,050 177,223 71,960 5. A.E. Partners 1989 550,000 -0- 550,000 157,254 71,270 6. A.E. Partners 1990 887,500 -0- 887,500 258,444 82,850 7. A.E. Nineties-10 2,200,000 -0- 2,200,000 544,949 80,884 8. A.E. Nineties-11 750,000 -0- 761,802 (2) 224,165 131,234 9. A.E. Partners 1991 868,750 -0- 867,500 230,774 107,394 10. A.E. Nineties-12 2,212,500 -0- 2,272,017 (2) 594,981 121,580 11. A.E. Nineties-JV 92 4,004,813 -0- 4,157,700 1,018,139 213,043 12. A.E. Partners 1992 600,000 -0- 600,000 130,877 53,513 13. A.E. Nineties-Public #1 2,988,960 -0- 3,026,348 (2) 562,346 117,826 14. A.E. Nineties-1993 Ltd. 3,753,937 -0- 3,480,656 (2) 714,508 141,038 15. A.E. Partners 1993 700,000 -0- 689,940 (2) 168,111 39,375 16. A.E. Nineties-Public #2 3,323,920 -0- 3,324,668 552,709 102,279 17. A.E. Nineties-14 9,940,045 -0- 9,512,015 (2) 1,897,109 367,994 18. A.E. Partners 1994 892,500 -0- 892,500 157,315 46,368 19. A.E. Nineties-Public #3 5,800,990 -0- 5,800,990 875,753 170,817 20. A.E. Nineties-15 10,954,715 -0- 9,859,244 (2) 1,767,373 345,589 21. A.E. Partners 1995 600,000 -0- 600,000 95,499 17,283 22. A.E. Nineties-Public #4 6,991,350 -0- 6,991,350 1,021,839 187,604 23. A.E. Nineties-16 10,955,465 -0- 10,955,465 1,336,388 226,658 24. A.E. Partners 1996 800,000 -0- 800,000 129,023 21,995 25. A.E. Nineties-Public #5 7,992,240 -0- 7,992,240 967,183 176,547 26. A.E. Nineties-17 8,813,488 -0- 8,813,488 1,043,806 178,011 27. A.E. Nineties-Public #6 9,901,025 -0- 9,901,025 1,165,594 193,863 28. A.E. Partners 1997 506,250 -0- 506,250 68,935 11,805 29. A.E. Nineties-18 11,391,673 -0- 11,391,673 1,386,758 220,717 30. A.E. Nineties-Public #7 11,988,350 -0- 11,988,350 1,244,704 180,021 31. A.E. Partners 1998 1,740,000 -0- 1,740,000 216,397 21,350 32. A.E. Nineties-19 15,720,450 -0- 15,720,450 1,567,585 218,445 33. A.E. Nineties-Public #8 11,088,975 -0- 11,088,975 1,107,323 134,387 34. A.E. Partners 1999 450,000 -0- 450,000 40,204 2,991 35. 1999 Viking Resources LP 4,555,210 -0- 4,555,210 1,011,016 0 36. Atlas America-Series 20 18,809,150 -0- 16,937,149 1,871,428 194,565 37. Atlas America-Public #9 14,905,465 -0- 13,509,454 1,525,480 131,531 38. Atlas America-Series 21-A 12,510,713 -0- 11,428,689 866,080 90,679 39. Atlas America-Series 21-B 17,411,825 -0- 15,851,425 1,009,150 100,906 40. Atlas America-Public #10 21,281,170 -0- 19,311,328 986,269 94,133 41. Atlas America-Series 22 10,156,375 -0- 9,233,970 365,071 31,826 42. Atlas America-Series 23 9,644,550 -0- 8,820,734 199,422 20,400 43. Atlas America-Public #11 31,178,145 -0- 28,506,485 169,798 21,469 44. Atlas America - Series 24-2003 (A) 14,363,955 -0- 13,080,714 0 0
- --------------- (1) Excluding the managing general partner's capital contributions. (2) Includes additional drilling costs paid with production revenues. 43 MANAGEMENT Managing General Partner and Operator The partnerships will have no officers or directors. Instead, Atlas Resources, Inc., a Pennsylvania corporation which was incorporated in 1979, will serve as the managing general partner of each partnership. Atlas Resources' affiliate Atlas Energy Group, Inc., an Ohio corporation which was the first of the Atlas group of companies, was incorporated in 1973. Atlas Energy Group, Inc. will serve as the partnership's general drilling contractor and operator in Ohio. As of January 1, 2003, the managing general partner and its affiliates operated approximately 4,416 natural gas and oil wells located in Ohio, Pennsylvania and New York. Since 1985 the managing general partner has sponsored 11 public and 32 private partnerships to conduct natural gas drilling and development activities in Pennsylvania, Ohio, and New York. In these partnerships the managing general partner and its affiliates acted as the operator and the general drilling contractor and were responsible for drilling, completing, and operating the wells. Atlas Resources has a 97% completion rate for wells drilled by its development partnerships. In September 1998, Atlas Energy Group, Inc., the former parent company of the managing general partner, merged into Atlas America, Inc., a Delaware holding company. Atlas America is a wholly-owned subsidiary of Resource America, Inc., which is sometimes referred to in this prospectus as Resource America. Resource America is a publicly-traded company with a total capitalization in excess of $400 million, and is principally engaged in energy, energy finance, real estate finance, and equipment leasing. Resource America, which includes the managing general partner as a subsidiary, was listed among the top 100 leaders in natural gas and oil production in the Oil and Gas Journal, October 16, 2000. The managing general partner depends on its parent company, Atlas America, for management and administrative functions and financing for capital expenditures as described below in " - Transactions With Management and Affiliates." Atlas America has and is continuing the existing business of Atlas Energy Group, Inc. It is headquartered at 311 Rouser Road, Moon Township, Pennsylvania 15108, near the Pittsburgh International Airport, which is also the managing general partner's primary office. Officers, Directors and Other Key Personnel The officers and directors of the managing general partner will serve until their successors are elected. The officers, directors, and key personnel of the managing general partner are as follows:
NAME AGE POSITION OR OFFICE - ------------------------- ------ ------------------------------------------------------------------------- Freddie M. Kotek 47 Chairman of the Board of Directors, Chief Executive Officer and President Frank P. Carolas 43 Executive Vice President - Land and Geology and a Director Jeffrey C. Simmons 44 Executive Vice President - Operations and a Director Jack L. Hollander 47 Senior Vice President - Direct Participation Programs Nancy J. McGurk 47 Senior Vice President, Chief Financial Officer and Chief Accounting Officer Michael L. Staines 54 Senior Vice President, Secretary and a Director Michael G. Hartzell 47 Vice President - Land Administration Donald R. Laughlin 55 Vice President - Drilling and Production Darshan V. Patel 32 Chief Legal Officer Marci F. Bleichmar 33 Vice President of Marketing Sherwood S. Lutz 52 Senior Geologist/Manager of Geology Michael W. Brecko 45 Director of Energy Sales Karen A. Black 42 Vice President - Partnership Administration Justin T. Atkinson 30 Director of Due Diligence Winifred C. Loncar 62 Director of Investor Services
44 With respect to the biographical information set forth below: o the approximate amount of an individual's professional time devoted to the business and affairs of the managing general partner and Atlas America have been aggregated because there is no reasonable method for them to distinguish their activities between the two companies; and o for those individuals who also hold senior positions with other affiliates of the managing general partner, if it is stated that they devote approximately 100% of their professional time to the managing general partner and Atlas America, it is because either the other affiliates are not currently active in drilling new wells, such as Viking Resources or Resource Energy, and the individuals are not required to devote a material amount of their professional time to the affiliates, or there is no reasonable method to distinguish their activities between the managing general partner and Atlas America as compared with the other affiliates of the managing general partner, such as Viking Resources or Resource Energy. Freddie M. Kotek. President and Chief Executive Officer since 2002 and Chairman of the Board of Directors since 2001. Mr. Kotek is employed by Resource America from 1993 to the present in various capacities and is currently Senior Vice President of Resource America. Mr. Kotek received a Bachelor of Arts degree from Rutgers College in 1977 with high honors in Economics. He also received a Master in Business Administration degree from the Harvard Graduate School of Business Administration in 1981. Mr. Kotek devotes approximately 80% of his professional time to the business and affairs of the managing general partner and Atlas America, and the remainder of his professional time to the business and affairs of the managing general partner's affiliates. Frank P. Carolas. Executive Vice President-Land and Geology and a Director since January, 2001. Mr. Carolas also serves as Executive Vice President-Land and Geology of Atlas America since January, 2001 and a Director since January, 2002. Mr. Carolas served as Vice President of Land and Geology for the managing general partner from July 1999 until 2001 and for Atlas America from 1998 until 2001. Before that Mr. Carolas served as Vice President of Atlas Energy Group, Inc. from 1997 until 1998, which was the former parent company of the managing general partner. Mr. Carolas is a certified petroleum geologist and has been with Atlas Resources and its affiliates since 1981. He received a Bachelor of Science degree in Geology from Pennsylvania State University in 1981 and is an active member of the American Association of Petroleum Geologists. Mr. Carolas devotes approximately 100% of his professional time to the business and affairs of the managing general partner and Atlas America. Jeffrey C. Simmons. Executive Vice President-Operations and a Director since January, 2001. Mr. Simmons also serves as Executive Vice President-Operations of Atlas America since January, 2001 and a Director since January, 2002. Mr. Simmons served as Vice President of Operations for the managing general partner from July 1999 until 2001 and for Atlas America from 1998 until 2001. Mr. Simmons also serves as Vice President of Atlas Energy Corp., Atlas Energy Group, Inc., PA Industrial Energy, Inc., Viking Resources, Corp., and Atlas Pipeline Partners G.P., President of REI-NY, Inc. and Resource Well Services, Inc., and Executive Vice President of Atlas Noble Corp. Mr. Simmons joined Resource America in 1986 as senior petroleum engineer. From 1988 through 1994 he served as director of production and as president of Resource Well Services, Inc., a subsidiary of Resource America. He was then promoted to vice president of Resource Energy, Inc., the energy subsidiary of Resource America formed in 1993. In 1997 he was promoted to executive vice president, chief operating officer and director of Resource Energy, Inc., a position he currently holds. Before Mr. Simmons' career with Resource America, he had worked with Core Laboratories, Inc., of Dallas, Texas, and PNC Bank of Pittsburgh. Mr. Simmons received his Petroleum Engineering degree from Marietta College and his Masters degree in Business Administration from Ashland University. He is a Board Member of the Ohio Oil and Gas Association, the Independent Oil and Gas Association of New York, and the Ohio Section of the Society of Petroleum Engineers. Mr. Simmons devotes approximately 80% of his professional time to the business and affairs of the managing general partner and Atlas America, and the remainder of his professional time to the business and affairs of the managing general partner's affiliates, primarily Viking Resources and Resource Energy. 45 Jack L. Hollander. Senior Vice President - Direct Participation Programs since January, 2002. Mr. Hollander also serves as Senior Vice President - Direct Participation Programs of Atlas America since January, 2002. Mr. Hollander served as Vice President - Direct Participation Programs for the managing general partner and Atlas America from 2001 until January, 2002. Mr. Hollander began his career serving as in-house tax counsel for Integrated Resources, Inc., a large diversified financial services company from 1982 to 1990. He then went on to practice law with Rattet, Hollander & Pasternak with a concentration in tax matters, real estate transactions, and consulted with and assisted technology companies in raising capital until joining the managing general partner in January 2001. Mr. Hollander earned a Bachelor of Science degree from the University of Rhode Island in 1978, his law degree from Brooklyn Law School in 1981, and a Master of Law degree in Taxation from New York University School of Law Graduate Division in 1982. Mr. Hollander is a member of the New York State bar, the Investment Program Association, and the Financial Planning Association. Mr. Hollander devotes approximately 100% of his professional time to the business and affairs of the managing general partner and Atlas America. Nancy J. McGurk. Senior Vice President, Chief Financial Officer and Chief Accounting Officer since January, 2002. Ms. McGurk also serves as Senior Vice President, Chief Financial Officer, and Chief Accounting Officer of Atlas America since January, 2002. Ms. McGurk served as Vice President, Chief Financial Officer and Chief Accounting Officer of the managing general partner and Atlas America from January, 2001 to January, 2002. Ms. McGurk has been Vice President of Resource America since 1992 and before that she had served as Treasurer and Chief Accounting Officer of Resource America since 1989. Also, since 1995 Ms. McGurk has served as Vice President - Finance of Resource Energy, Inc. Ms. McGurk devotes approximately 20% of her professional time to the business and affairs of the managing general partner and Atlas America, and the remainder of her professional time to the business and affairs of the managing general partner's affiliates. Michael L. Staines. Senior Vice President, Secretary, and a Director since 1998. Mr. Staines is also Executive Vice President, Secretary, and a Director of Atlas America since 1998; Senior Vice President of Resource America since 1989; Secretary of Resource America from 1989 to 1998; Director of Resource America from 1989 to 2000; President, Secretary, and a Director of Resource Energy, Inc., an energy subsidiary of Resource America, since 1993; President of Atlas Pipeline Partners GP, LLC since 2001; and Chief Operating Officer, Secretary, and Managing Board Member of Atlas Pipeline Partners GP, LLC since its formation in 1999. Mr. Staines is a member of the Ohio Oil and Gas Association and the Independent Oil and Gas Association of New York. Mr. Staines received a Bachelor of Science degree from Cornell University in 1971 and a Master of Business degree from Drexel University in 1977. Mr. Staines devotes approximately 10% of his professional time to the business and affairs of the managing general partner and Atlas America, and the remainder of his professional time to the business and affairs of the managing general partner's affiliates. Michael G. Hartzell. Vice President - Land Administration since 2001. Mr. Hartzell has been with Atlas Energy Group, Inc. since 1980. He began his career with Atlas Energy Group, Inc. as a Land Department Representative and was promoted to Land Manager of the Indiana County, Pennsylvania operations in 1981. He relocated to the Atlas Energy Group, Inc. office in Mercer, Pennsylvania in 1985 where he served as Land Manager until being promoted to General Manager in 1996. In 2000, Mr. Hartzell was promoted to Senior Land Coordinator for Atlas America, Inc., and he manages all Land Department functions. Mr. Hartzell serves on the Environmental Committee of the Independent Oil and Gas Association of Pennsylvania and is a past Chairman of the Committee. Mr. Hartzell devotes approximately 100% of his professional time to the business and affairs of the managing general partner and Atlas America. Donald R. Laughlin. Vice President-Drilling and Production since January 2002. Mr. Laughlin joined Atlas America as Senior Drilling Engineer in May, 2001 and has over thirty years of experience in the Appalachian Basin. Before joining Atlas America, Mr. Laughlin was employed with Columbia Gas Transmission Corporation from 1995 to May 2001 where he became Vice President Drilling and Production. From 1989 to 1995 Mr. Laughlin was employed by Cabot Oil & Gas Corporation as Manager of Drilling Operations and Manager of Technical Services; from 1977 to 1989 he was employed by Doran & Associates, Inc. as Vice President-Operations; and from 1970 to 1977 he was employed by Columbia Gas Transmission Corporation as Drilling Engineer and Gas Storage Engineer. Mr. Laughlin received his Petroleum Engineering degree from the University of Pittsburgh in 1970. He is a member of the Society of Petroleum Engineers. Mr. Laughlin 46 devotes approximately 100% of his professional time to the business and affairs of the managing general partner and Atlas America. Darshan V. Patel. Chief Legal Officer since January, 2002. Mr. Patel also serves as Associate General Counsel for Resource America, Inc. since 2001, and Vice President of Anthem Securities, Inc. since August, 2002. Mr. Patel received a Bachelor of Arts degree from Boston University in 1992. He also received a Juris Doctorate degree from American University's Washington College of Law in 1995. From 1996 to 1998, Mr. Patel was associated with the law firm of Glynn & Associates, in Flemington, N.J., practicing litigation and real estate. From 1998 to 2000, Mr. Patel was associated with the law firm of Berman, Paley, Goldstein & Kannry, in New York, N.Y., practicing commercial litigation. Mr. Patel devotes approximately 20% of his professional time to the business and affairs of the managing general partner and Atlas America, and the remainder of his professional time to the business and affairs of the managing general partner's affiliates. Marci F. Bleichmar. Vice President of Marketing for the managing general partner since January 2003. Before that Ms. Bleichmar served as Director of Marketing for the managing general partner and Atlas America since February 2001 when she joined the managing general partner and Atlas America. Ms. Bleichmar also serves as Director of Marketing for Resource America, Inc. since February 2001. From March 2000 through February 2001, Ms. Bleichmar served as Director of Marketing for Jacob Asset Management. From March 1998 through March 2000, she served as an Account Executive at Bloomberg Financial Services LP. From November 1994 through March 1998, Ms. Bleichmar was an Associate on the Derivatives Trading Desk of JP Morgan. Ms. Bleichmar devotes approximately 100% of her professional time to the business and affairs of the managing general partner and Atlas America. Sherwood S. Lutz. Senior Geologist/Manager of Geology. In 1996 Mr. Lutz joined Viking Resources as senior geologist, which was purchased by Resource America in 1999. Since 1999 Mr. Lutz has been a senior geologist for the managing general partner and Atlas America. Mr. Lutz received his Bachelor of Science degree in Geological Sciences from the Pennsylvania State University in 1973. Mr. Lutz is a certified petroleum geologist with the American Association of Petroleum Geologists as well as a licensed professional geologist in Pennsylvania. Mr. Lutz devotes approximately 100% of his professional time to the business and affairs of the managing general partner and Atlas America. Michael W. Brecko. Director of Energy Sales since November 2002. Mr. Brecko has over 16 years of natural gas marketing experience in the oil and natural gas industry. Mr. Brecko is a 1980 graduate from The Pennsylvania State University with a Bachelor of Science degree in Civil Engineering. His career in natural gas marketing began when he joined Equitable Gas Company, a local distribution company as a marketing representative in the commercial/ industrial marketing division from May 1986 to August 1992. He subsequently joined O&R Energy, a subsidiary of Orange and Rockland Utilities, as regional marketing manager from August 1992 to November 1993. Beginning in December 1993 through July 2001, Mr. Brecko worked for Cabot Oil & Gas Corporation, a mid-sized Appalachian oil and natural gas producer as an account executive and was promoted in August 1998 to natural gas trader. In November 2001, he joined Sprague Energy Corporation, a multi-energy sourced company as a regional account manager before joining Atlas America in 2002. Mr. Brecko devotes approximately 100% of his professional time to the business and affairs of the managing general partner and Atlas America. Karen A. Black. Vice President - Partnership Administration since February 2003. Ms. Black is also Vice President and Financial and Operations Principal of Anthem Securities since October 2002. Ms. Black joined the managing general partner and Atlas America in July 2000 and served as manager of production, revenue and partnership accounting from July 2000 through October 2001, after which she served as manager and financial analyst until her appointment as Vice President - Partnership Administration. Before joining the managing general partner in 2000, Ms. Black was associated with Texas Keystone, Inc. as controller from April 1997 through June 2000. Ms. Black was employed as a tax accountant for Sobol Bosco & Associates, Inc. from May 1996 through March 1997. Ms. Black devotes approximately 50% of her professional time to the business and affairs of the managing general partner and Atlas America, and the remainder of her professional time to the business and affairs of Anthem Securities. 47 Justin T. Atkinson. Director of Due Diligence since February 2003. Mr. Atkinson also serves as Vice President and Chief Compliance Officer of Anthem Securities since October 2002 and before that Mr. Atkinson served as assistant compliance officer of Anthem Securities from December 2001 until October 2002. Before his employment with the managing general partner, Mr. Atkinson was a manager of investor and broker/dealer relations with Viking Resources Corporation from 1996 until November 2001. Mr. Atkinson earned a Bachelor of Arts degree in Business Management from Walsh University in North Canton, Ohio. Mr. Atkinson devotes approximately 25% of his professional time to the business and affairs of the managing general partner and Atlas America, and the remainder of his professional time to the business and affairs of Anthem Securities. Winifred C. Loncar, Director of Investor Services since February, 2003. Ms. Loncar previously held the position of manager of investor services from the inception of the investor service department in 1990 to February 2003. Before that she was executive secretary to the managing general partner. Ms. Loncar received a degree in business from Point Park College in 1998. Ms. Loncar devotes approximately 100% of her professional time to the business and affairs of the managing general partner and Atlas America. Atlas America, Inc., a Delaware Holding Company As of January 1, 2003, the Board of Directors for Atlas America includes the following:
NAME AGE POSITION OR OFFICE - ------------------------- ------ -------------------------------------------------------------------------------------------- Edward E. Cohen 64 Chairman of the Board Jonathan Z. Cohen 32 Vice Chairman Freddie M. Kotek 47 Director Michael L. Staines 53 Director John S. White 62 Director JoAnn Bagnell 74 Director Frank P. Carolas 43 Director Jeffrey C. Simmons 44 Director
See "- Officers, Directors and Other Key Personnel," above, for biographical information on certain of these individuals who are also officers and/or directors of the managing general partner. Biographical information on the other directors will be provided by the managing general partner on request. The managing general partner and its affiliates under Atlas America employ a total of approximately one hundred thirty-eight persons in its energy operations, consisting of six drilling and completion personnel, eighty production/measurement personnel, six pipeline personnel, thirteen well services personnel, four purchasing personnel, one reservoir engineer, one health, environment and safety person, one gas marketing person, four leasing personnel, five geologists, three well site construction personnel, eleven land administration personnel, and three office services personnel. At September 30, 2002 Atlas America and its affiliates had more than $360 million of energy assets under management. 48 Organizational Diagram (1) This organizational diagram does not include all of the subsidiaries of Resource America. [GRAPHIC OMITTED] - --------------- (1) Resource Energy, Viking Resources, and Atlas Noble Corporation are also engaged in the oil and gas business. Resource Energy has been an energy subsidiary of Resource America since 1993. Resource America acquired Viking Resources in August 1999, and Atlas Noble Corporation was formed in October 2000 after Resource America acquired all of the assets of Kingston Oil Corporation. Atlas America manages their assets and employees including sharing common employees. Also, many of the officers and directors of the managing general partner serve as officers and directors of those entities. Remuneration No officer or director of the managing general partner will receive any direct remuneration or other compensation from the partnerships. These persons will receive compensation solely from affiliated companies of the managing general partner. Security Ownership of Certain Beneficial Owners Resource America owns 100% of the common stock of Atlas America, which owns 100% of the common stock of AIC, Inc., which owns 100% of the common stock of the managing general partner. The officers and directors of AIC, Inc. are Jonathan Z. Cohen, Michael L. Staines, Frank P. Carolas and Jeffrey C. Simmons. The biographies of Messrs. Staines, Carolas and Simmons are set forth above. Transactions with Management and Affiliates The managing general partner depends on its parent company, Atlas America, for management and administrative functions and financing for capital expenditures. The managing general partner pays a management fee to Atlas America for management and administrative services, which amounted to $10.5 million and $6.4 million for the years ended 49 September 30, 2002 and 2001, respectively. (See "Financial Information Concerning the Managing General Partner and Atlas America Public #12-2003 Limited Partnership.") Atlas Energy Group, Inc. shareholders are eligible to receive incentive compensation should Atlas Energy Group, Inc.'s post-acquisition earnings exceed a specified amount during the five years following the merger which was in September 1998. The incentive compensation is equal to 10% of Atlas Energy Group, Inc.'s aggregate earnings in excess of that amount equal to an annual, but uncompounded, return of 15% on $63 million which is increased to include any amount paid by Resource America for any post-merger energy acquisitions. Incentive compensation is payable, at Resource America's option, in cash or in shares of Resource America's common stock, valued at the average closing price of Resource America's common stock for the 10 trading days before September 30, 2003. The managing general partner and its officers, directors and affiliates have in the past invested, and may in the future invest, in partnerships sponsored by the managing general partner. They may also subscribe for units in each partnership as described in "Plan of Distribution." MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION, RESULTS OF OPERATIONS, LIQUIDITY AND CAPITAL RESOURCES None of the partnerships composing the program have been formed other than the first partnership, Atlas America Public #12-2003 Limited Partnership. Each partnership will be formed as a limited partnership under the Delaware Revised Uniform Limited Partnership Act before the initial closing of the partnership and breaking escrow as discussed in "Terms of the Offering - Activation of the Partnerships." Thus, the partnerships formed or to be formed have not included any historical information in this prospectus since they: o have no net worth; o do not own any properties on which wells will be drilled; o have no third-party investors; o have not conducted any operations; and o have not made any distributions. (See "Capitalization and Source of Funds and Use of Proceeds", "Proposed Activities," "Competition, Markets and Regulation," and "Financial Information Concerning the Managing General Partner and Atlas America Public #12-2003 Limited Partnership.") Each partnership will depend on the proceeds of this offering and the managing general partner's capital contributions to carry out its proposed activities. Each partnership intends to use its subscription proceeds to pay the intangible drilling costs, the investors' share of equipment costs, and the investors' share of any cost overruns of drilling and completing the partnership's wells. To the extent that a partnership's subscription proceeds are less than the nonbinding targeted maximum amounts described in "Terms of the Offering - Subscription to a Partnership," fewer wells will be drilled and the partnership's ability to diversify its drilling activities will be reduced. The managing general partner believes that each partnership's liquidity requirements will be satisfied from the following: o the subscription proceeds of this offering; 50 o the managing general partner's capital contributions; o the cash flow from future operations; and o partnership borrowings, if necessary. The managing general partner also anticipates that no additional funds will be required for operating costs before a partnership begins receiving production revenues from its wells. Substantially all the subscription proceeds of you and the other investors in a partnership will be committed or expended after the offering of the partnership closes. If a partnership requires additional funds for cost overruns or additional development or remedial work after a well begins producing, then these funds may be provided by: o subscription proceeds, if available, drilling fewer wells, or acquiring a lesser working interest in one or more wells; o borrowings from the managing general partner or its affiliates; or o retaining partnership revenues. There will be no borrowings from third-parties. The amount that may be borrowed by a partnership from the managing general partner and its affiliates may not at any time exceed 5% of the partnership's subscription proceeds from you and the other investors and must be without recourse to you and the other investors. The partnership's repayment of any borrowings would be from partnership production revenues and would reduce or delay your cash distributions. If the managing general partner loans money to a partnership, which it is not required to do, then: o the interest charged to the partnership must not exceed the managing general partner's interest cost or the interest that would be charged to the partnership without reference to the managing general partner's financial abilities or guarantees by unrelated lenders, on comparable loans for the same purpose; and o the managing general partner may not receive points or other financing charges or fees, although the actual amount of the charges incurred from third-party lenders may be reimbursed to the managing general partner. Currently, Atlas America, Inc. (the "borrower"), which is an affiliate of the managing general partner, participates in a $75 million revolving credit facility with a group of banks that includes Union Bank of California, N.A., as syndication agent with Wachovia Bank, N.A. as the agent and issuing bank. The managing general partner, Resource America, Inc. and various energy subsidiaries of Resource America are guarantors of the credit agreement. This facility has an initial borrowing base of $45 million, which may be increased to $75 million subject to growth in the oil and gas reserves of the borrower and the guarantors. At June 30, 2003, the borrowing base was $52.5 million. Borrowings under the facility are collateralized by substantially all the assets of Atlas America, the managing general partner and the other guarantors. This includes the managing general partner's interests in its partnerships, but does not include any investor's interest in a partnership. A breach of the credit agreement by the borrower constitutes a default under the loan. The credit facility has a term ending in July 2005. At June 30, 2003, the borrower had an outstanding balance of approximately $30 million and also had a $275,000 letter of credit issued under the facility. The managing general partner depends on its parent company, Atlas America, for management and administrative functions and financing for capital expenditures. The managing general partner pays a management fee to Atlas America for management and administrative services, which amounted to $10.5 million and $6.4 million for the years ended September 30, 2002 and 2001, respectively. See footnotes 3 and 4 to the managing general partner's audited financial statements and 51 footnote 4 to the managing general partner's unaudited financial statements for more details concerning the credit facility and inter-company borrowings in "Financial Information Concerning the Managing General Partner and Atlas America Public #12-2003 Limited Partnership." PROPOSED ACTIVITIES Overview of Drilling Activities The managing general partner anticipates that all the wells of each partnership will be development wells, which means a well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive. Stratigraphic means a layer of rock which has characteristics that differentiate it from the rocks above and below it. Stratigraphic horizon generally means that part of a formation or layer of rock with sufficient porosity and permeability to form a petroleum reservoir. Also, the majority of the wells will be classified as natural gas wells, which may produce a small amount of oil, although some of the wells may be classified as oil wells. Each partnership will be a separate business entity from the other partnerships, and you will be a partner only in the partnership in which you invest. You will have no interest in the business, assets or tax benefits of the other partnerships unless you also invest in the other partnerships. Thus, your investment return will depend solely on the operations and success or lack of success of the particular partnership in which you invest. Each partnership generally will drill different wells, but they may own working interests and participate in drilling and completing one or more of the same wells. The number of wells to be drilled by a partnership cannot be determined precisely in advance of funding of a partnership and is determined by: o the amount of funds raised for that partnership; o where the wells are drilled; o the specific prospects drilled by that partnership; o if there are any cost overruns on the investors' share of well costs; and o the partnership's percentage of working interest owned in the wells, which could range from 25% to 100%. The managing general partner, however, anticipates that a partnership will drill approximately: o 5 wells in which it has a 100% working interest if the minimum subscriptions of $1 million are received; and o 50 wells in which it has a 100% working interest for every $10 million of subscriptions received. Before the managing general partner selects a prospect on which a well will be drilled by a partnership, it will review all available geologic and production data for wells located in the vicinity of the proposed well including, but not limited to: o various well logs; o completion reports; o plugging reports; and o production reports. 52 For example, production information from surrounding wells in the area is an important indicator in evaluating the economic potential of a proposed well to be drilled. It has been the managing general partner's experience that natural gas production from wells drilled to the formations or the reservoirs in the primary areas is reasonably consistent with nearby wells, although from time to time there can be great differences in the natural gas volumes and performance of wells located close together. However, production information is only one factor and the managing general partner may propose a well to be drilled by a partnership because geologic trends in the immediate area where production has already been established, such as sand thickness, porosities and water saturations, lead the managing general partner to believe that the proposed well locations will have similar production. Primary Areas of Operations The managing general partner will not decide on the majority of the specific wells to be drilled in any partnership until the offering of units in that partnership has ended. However, the managing general partner intends that Atlas America Public #12-2003 Limited Partnership, which must close on or before December 31, 2003, will drill the prospects described in "Appendix A - Information Regarding Currently Proposed Prospects for Atlas America Public #12-2003 Limited Partnership." These prospects represent the wells to be drilled if approximately $15 million of subscription proceeds are received, which is a portion of the nonbinding targeted maximum subscription proceeds described in "Terms of the Offering - Subscription to a Partnership." If there are adverse events with respect to any of the currently proposed prospects, the managing general partner will substitute the partnership's prospects as discussed below in "- Interest of Parties." The managing general partner also anticipates that it will designate a portion of each partnership's prospects in the partnerships designated Atlas America Public #12-2004( ) Limited Partnership by supplement or an amendment to the registration statement. This means that you will not be able to evaluate the majority of the specific prospects that will be drilled by your partnership. However, by waiting as long as possible before selecting all of the specific prospects to be drilled by a partnership, the managing general partner may acquire additional information to helpit select better prospects for the partnership, and it may be able to include prospects which were not available when this prospectus was written or even when the partnership was closed. This section includes a general description of the areas where the managing general partner anticipates partnership wells may be drilled. If additional areas are added, then this information will be supplemented. As discussed below, the three primary areas for the partnerships' drilling activities are: o the Clinton/Medina Geological Formation in western Pennsylvania that also covers an area in eastern Ohio primarily in Stark, Mahoning, Trumbull and Portage Counties; o the Mississippian/Upper Devonian Sandstone reservoirs in Fayette and Greene Counties, Pennsylvania; and o the Upper Devonian Sandstone Reservoirs in Armstrong County, Pennsylvania. Fayette County, Greene County and Armstrong County also are in western Pennsylvania. The Clinton/Medina geological formation in Pennsylvania and Ohio is the same geological formation, although in Pennsylvania it is often referred to as the Medina/Whirlpool geological formation. For purposes of this prospectus, the term Clinton/Medina geological formation is used for both Ohio and Pennsylvania. The wells drilled to the Clinton/Medina geological formation, regardless of whether they are situated in western Pennsylvania, eastern Ohio, western New York, or southern Ohio, and the Mississippian and/or Upper Devonian Sandstone reservoirs have the following similarities: o geological features such as structure and faulting are not generally factors used in finding commercial production from a well drilled to this formation or these reservoirs and the governing factors appear to be sand quality in terms of net pay zone thickness, porosity, and the effectiveness of fracture stimulation; 53 o a well drilled to this formation or these reservoirs usually requires hydraulic fracturing of the formation to stimulate productive capacity; o generally, natural gas from a well drilled to this formation or these reservoirs is produced at rates which decline rapidly during the first few years of operations, and although the well can produce for many years, a proportionately larger amount of production can be expected within the first several years; and o it has been the managing general partner's experience that natural gas production from wells drilled to this formation or these reservoirs is reasonably consistent with nearby wells, although from time to time there can be great differences in the natural gas volumes and performance of wells located close together. The managing general partner anticipates that the majority of the subscription proceeds of each partnership will be expended in the primary areas, although some of the subscription proceeds of each partnership may be expended in the secondary areas. Clinton/Medina Geological Formation in Western Pennsylvania. The Clinton/ Medina geological formation is a blanket sandstone found throughout most of the northwestern edge of the Appalachian Basin. The Clinton/Medina is described in petroleum industry terms as a "tight" sandstone with porosity ranging from 6% to 12% and with very low permeability. Porosity is the percentage of void space between sand grains that is available for occupancy by either liquids or gases; and permeability is the property of porous rock that allows fluids or gas to flow through it. Based on the managing general partner's experience, it anticipates that all the natural gas wells will be completed and fraced in two different zones of the Clinton/Medina geological feature. See the geologic evaluation and the model decline curve prepared by United Energy Development Consultants, Inc., an independent geological and engineering firm, in "Appendix A - Information Regarding Currently Proposed Prospects for Atlas America Public #12-2003 Limited Partnership" for a discussion of the development of the Clinton/Medina Geological Formation in western Pennsylvania, which also covers an area in eastern Ohio primarily in Stark, Mahoning, Trumbull, and Portage Counties. The wells in the Clinton/Medina geological formation in western Pennsylvania and eastern Ohio will be: o primarily situated in Crawford, Mercer, Lawrence, Warren, and Venango Counties, Pennsylvania, and Stark, Mahoning, Trumbull and Portage Counties, Ohio; o situated on approximately 50 acres, subject to adjustment to take into account lease boundaries; o drilled at least 1,650 feet from each other in Pennsylvania, which is greater than the 660 feet minimum distance allowed by state law or local practice to protect against drainage from adjacent wells, and drilled at least 1,000 feet from each other in Ohio; o drilled from approximately 5,100 to 6,300 feet in depth; o classified as natural gas wells which may produce a small amount of oil, although the wells in eastern Ohio may be classified as oil wells; and o primarily connected to the gathering system owned by Atlas Pipeline Partners and have their natural gas production primarily marketed to First Energy Solutions Corporation as described below in " - Sale of Natural Gas and Oil Production". Also, see "- Secondary Areas of Operations,, below, for a discussion of the Clinton/Medina geological formation in western New York and southern Ohio. Mississippian/Upper Devonian Sandstone Reservoirs, Fayette County, Pennsylvania. The Mississippian/Upper Devonian Sandstone reservoirs are discontinuous lens-shaped accumulations found throughout most of the Appalachian 54 Basin. The Mississippian/Upper Devonian Sandstone reservoirs have porosities ranging from 5% to 20% with attendant permeabilities. See the geologic evaluation prepared by United Energy Development Consultants, Inc. for a discussion of the development of the Mississippian/Upper Devonian Sandstone reservoirs in Fayette and Greene Counties, Pennsylvania. The wells in the Mississippian/Upper Devonian Sandstone reservoirs will be: o situated on approximately 20 acres, subject to adjustment to take into account lease boundaries; o drilled at least 1,000 feet from each other, although existing wells may be re-entered by parties other than the partnership even though they are not 1,000 feet from each other; o drilled from approximately 1,900 to 4,500 feet in depth; o classified as natural gas wells which may produce a small amount of oil; and o primarily connected to the gathering system owned by Atlas Pipeline Partners and have their natural gas production primarily marketed to First Energy Solutions Corporation, although for the 12 month period from March 31, 2003 to March 31, 2004 the natural gas production will be marketed primarily to Colonial Energy, Inc. and UGI Energy Services as described below in "- Sale of Natural Gas and Oil Production." Upper Devonian Sandstone Reservoirs, Armstrong County, Pennsylvania. The Upper Devonian Sandstone reservoirs are discontinuous lens-shaped accumulations found throughout most of the Appalachian Basin. The Upper Devonian Sandstone reservoirs have porosities ranging from greater than 5% to 20% with attendant permeabilities. See the geologic evaluation prepared by United Energy Development Consultants, Inc. for a discussion of the development of the Upper Devonian Sandstone Reservoir in Armstrong County, Pennsylvania. The prospects in Armstrong County, Pennsylvania were acquired from U.S. Energy Exploration Corporation as described below in "-Interest of Parties," and U.S. Energy will participate in the wells with the partnerships. The wells in the Upper Devonian Sandstone reservoirs will be: o situated on approximately 20 acres, subject to adjustment to take into account lease boundaries; o drilled at least 1,000 feet from each other, although under Pennsylvania law in certain circumstances a variance can be obtained, and out of the wells the managing general partner has drilled to date in this general area, some have been drilled less than 1,000 feet apart, but even in those cases the wells were approximately 980 feet or more from each other; o drilled from approximately 1,800 to 4,400 feet in depth; o classified as natural gas wells which may produce a small amount of oil; and o connected to a gathering system owned by U.S. Energy and have their natural gas production marketed by U.S. Energy as described below in "- Sale of Natural Gas and Oil Production." Secondary Areas of Operations The managing general partner also has reserved the right to use a portion of the subscription proceeds of each partnership to drill development wells in other areas of the Appalachian Basin. The secondary areas anticipated by the managing general partner are discussed below. Clinton/Medina Geological Formation in Western New York. Wells located in western New York and drilled to the Clinton/Medina geological formation will be: 55 o primarily situated in Chautauqua County; o situated on approximately 40 acres, subject to adjustment to take into account lease boundaries; o drilled from approximately 3,800 to 4,000 feet in depth; o drilled on leases with a net revenue interest of approximately 84.375% to 87.5%; o classified as natural gas wells which may produce a small amount of oil; and o connected to the gathering system owned by Atlas Pipeline Partners and have their natural gas production primarily marketed to First Energy Solutions Corporation, and/or commercial users in the area, although a portion of the natural gas production may be gathered and marketed by Great Lakes Energy Partners, L.L.C. as described below in " - Sale of Natural Gas and Oil Production." Mississippian Berea Sandstone in Eastern Ohio. Wells located in eastern Ohio and drilled to the Mississippian Berea Sandstone will be: o primarily situated in Columbiana County; o situated on approximately 5 acres, subject to adjustment to take into account lease boundaries; o drilled from approximately 850 to 950 feet in depth; o drilled on leases with a net revenue interest of approximately 84.375% to 87.5%; o classified as natural gas wells which may produce a small amount of oil; and o connected to the gathering system owned by Atlas Pipeline Partners and have their natural gas production primarily marketed to First Energy Solutions Corporation, as described below in " - Sale of Natural Gas and Oil Production." Devonian Oriskany Sandstone in Eastern Ohio. Wells located in eastern Ohio and drilled to the Devonian Oriskany Sandstone will be: o primarily situated in Tuscarawas County; o situated on approximately 40 acres, subject to adjustment to take into account lease boundaries; o drilled from approximately 3,800 to 4,200 feet in depth; o drilled on leases with a net revenue interest of approximately 84.375% to 87.5%; o classified as natural gas wells which may produce a small amount of oil; and o connected to the gathering system owned by Atlas Pipeline Partners and have their natural gas production primarily marketed to First Energy Solutions Corporation, although a portion of the natural gas production may be marketed by Dominion Field Services as described below in " - Sale of Natural Gas and Oil Production." Upper Devonian Sandstone in McKean County, Pennsylvania. Wells located in McKean County and drilled to the Upper Devonian Sandstones will be: 56 o primarily situated in McKean County; o situated on approximately 6 acres subject to adjustments to take into account lease boundaries; o drilled from approximately 2,000 to 2,500 feet in depth; o drilled on leases with a net revenue interest of approximately 84.375% to 87.5%; o classified as combination wells producing both natural gas and oil; and o connected to the gathering systems owned by Atlas Pipeline Partners and M&M Royalty, LTD. and have their natural gas production primarily marketed to M&M Royalty, LTD. as described below in " - Sale of Natural Gas and Oil Production." Clinton/Medina Geological Formation in Southern Ohio. Wells located in southern Ohio and drilled to the Clinton/Medina geological formation will be: o primarily situated in Noble, Washington, Guernsey, and Muskingum Counties; o situated on approximately 40 acres, subject to adjustment to take into account lease boundaries; o drilled at least 1,000 feet from each other; o drilled from approximately 4,900 to 6,500 feet in depth; o drilled on leases with a net revenue interest of approximately 82.5% to 87.5%; o classified as either natural gas wells or oil wells; and o primarily connected to the gathering system owned by Atlas Pipeline Partners if classified as natural gas wells and have their natural gas production primarily marketed by First Energy Solutions Corporation, although a portion of the natural gas production may be gathered and marketed by Triad Energy Corporation of West Virginia, Inc. as described below in " - Sale of Natural Gas and Oil Production." Additionally, the managing general partner anticipates that the leases in southern Ohio will have been originally acquired from a coal company and are subject to a provision that the well must be abandoned if it hinders the development of the coal. Thus, the managing general partner will not drill a well on any lease subject to this provision unless it covers lands that were previously mined. Although this does not totally eliminate the risk because the leases may cover other coal deposits that might be mined during the life of a well, the managing general partner may determine in its sole discretion that drilling wells on these previously mined leases would be in the best interests of the partnerships. Acquisition of Leases The managing general partner will have the right, in its sole discretion, to select the prospects which each partnership will drill. The managing general partner intends that Atlas America Public #12-2003 Limited Partnership, which must close on or before December 31, 2003, will drill the prospects described in "Appendix A - Information Regarding Currently Proposed Prospects for Atlas America Public #12-2003 Limited Partnership." The managing general partner also anticipates that it will designate a portion of each partnership's prospects in the partnerships designated Atlas America Public #12-2004(____) Limited Partnership by supplement or an amendment to the registration statement. The leases covering each prospect on which one well will be drilled will be acquired by a partnership from the managing general partner or its affiliates and credited to the managing general partner as a part of its required capital contribution to the 57 partnership. Neither the managing general partner nor its affiliates will receive any royalty or overriding royalty interest on any well. The managing general partner anticipates that it will select the prospects for each partnership, including any additional and/or substituted prospects, from the following: o leases in its and its affiliates' existing leasehold inventory; o leases that are subsequently acquired by it or its affiliates; or o leases owned by independent third-parties that may participate with the partnership in drilling wells. Most of the prospects acquired by a partnership will be in areas where the managing general partner or its affiliates have previously conducted drilling operations. The managing general partner believes that its and its affiliates' leasehold inventory and leases acquired from third-parties will be sufficient to provide all the prospects to be drilled by each partnership. The managing general partner and its affiliates are continually engaged in acquiring additional leasehold acreage in Pennsylvania, Ohio, and other areas of the United States. As of April 30, 2003, the managing general partner and its affiliates owned approximately: o 121,974 net acres of undeveloped lease acreage in Pennsylvania; o 60,841 net acres of undeveloped lease acreage in Ohio; o 5,301 net acres of undeveloped lease acreage in West Virginia; o 6,251 net acres of undeveloped lease acreage in Kentucky; and o 11,985 net acres of undeveloped lease acreage in New York. Most, if not all, of the prospects to be selected for the partnerships are expected to be single well proved undeveloped prospects. Thus, only one well will be drilled on each prospect and the number of prospects the managing general partner will assign to each partnership will be the same as the number of wells which the partnership has the funds to drill. This also means that the partnership, in all likelihood, will not farmout any acreage. However, the need for a farmout might arise, for example, if during drilling or subsequently the managing general partner determines there might be a productive horizon situated above (i.e. uphole) the target horizon, but the partnership does not have the funds to complete the well in the horizon or the completion of the horizon would be inconsistent with the partnership objectives. In this event, the managing general partner might determine to farmout the activity for the partnership. Generally, a farmout is an agreement in which the owner of the lease or existing well agrees to assign his interest in certain acreage under the lease or the existing well to an assignee subject to the assignee drilling one or more wells or completing or recompleting the existing well in one or more horizons. The owner would retain some interest in the assigned acreage or well. See "Conflicts of Interest - Conflicts Involving the Acquisition of Leases,, for the procedure for a farmout. Deep Drilling Rights Retained by Managing General Partner. In the areas where the Clinton/Medina is the primary geological formation, the lease assignments to each partnership will be limited to a depth of from the surface to the top of the Queenston geological formation, and the managing general partner will retain the deeper drilling rights beginning with the Queenston geological formation. In all other areas the lease assignments to each partnership will be limited to a depth of from the surface through the completion total depth of the well and the managing general partner will retain the deeper drilling rights. Because each partnership's objective is to conduct development drilling which would not be the case with the deeper formations, the managing general partner will retain the deeper formations including ownership of any coal bed methane production that might be obtained from the deeper formations. Conversely, as between a partnership and the 58 managing general partner, the partnership will own any coal bed methane production that might be obtained from the shallower formations that are not included in the deeper drilling rights retained by the managing general partner. The managing general partner believes that a partnership's development drilling in these areas will not provide any geological information that would assist it in evaluating drilling to deeper formations. Also, the amount of the credit the managing general partner receives for the leases it contributes to a partnership does not include any value allocable to the deeper drilling rights retained by it. If in the future the managing general partner undertakes any activities with respect to the deeper formations, including drilling an exploratory well, then the partnerships would not share in the profits from these activities, nor would they pay any of the associated costs. Interests of Parties Generally, production and revenues from a well drilled by a partnership will be net of the applicable landowner's royalty interest, which is typically 1/8th (12.5%) of gross production, and any interest in favor of third-parties such as an overriding royalty interest. Landowner's royalty interest generally means an interest that is created in favor of the landowner when an oil and gas lease is obtained; and overriding royalty interest generally means an interest which is created in favor of someone other than the landowner. In either case, the owner of the interest receives a specific percentage of the natural gas and oil production free and clear of all costs of development, operation, or maintenance of the well. This is compared with a working interest, which generally means an interest in the lease under which the owner of the interest must pay some portion of the cost of development, operation, or maintenance of the well. Also, the leases will be subject to terms that are customary in the industry such as free gas to the landowner-lessor for home heating requirements, etc. The managing general partner anticipates that each partnership generally will have a net revenue interest in its leases in its primary drilling areas as set forth in the chart below. Net revenue interest generally means the percentage of revenues the owner of an interest in a well is entitled to receive under the lease. The following chart expresses the percentage of production revenues that the managing general partner, the landowner, other third-parties, and you and the other investors in a partnership will share in from the wells in two of the three primary proposed areas. The third primary proposed area is discussed following the chart. The chart assumes that the partnership owns 100% of the working interest in the well. If a partnership acquires a lesser percentage working interest in a well, which will be the case in Armstrong County, then the partnership's net revenue interest in that well will decrease proportionately. The actual number, identity and percentage of working interests or other interests in prospects to be acquired by the partnerships will depend on, among other things: o the amount of subscription proceeds received in a partnership; o the latest geological and production data; o potential title or spacing problems; o availability and price of drilling services, tubular goods and services; o approvals by federal and state departments or agencies; o agreements with other working interest owners in the prospects; o farmins and farmouts; and o continuing review of other prospects that may be available. 59 Primary Areas. Clinton/Medina Geological Formation in Western Pennsylvania and Mississippian/ Upper Devonian Sandstone Reservoirs in Fayette and Greene Counties, Pennsylvania.
Partnership Third Party 87.5% Partnership Entity Interest Royalty Interest Net Revenue Interest(2) - ------ ------------ ---------------- ----------------------- Managing General Partner 32% partnership interest (1) 28.0% Investors 68% partnership interest (1) 59.5% 12.5% Landowner Royalty Third Party Interest 12.5% --------------------- 100.0% =====================
- --------------- (1) These percentages are for illustration purposes only and assume the managing general partner's minimum required capital contribution to each partnership of 25% and capital contributions of 75% from you and the other investors. The actual percentages are likely to be different because they will be based on the actual capital contributions of the managing general partner and you and the other investors. However, the managing general partner's total revenue share may not exceed 35% of partnership revenues regardless of the amount of its capital contributions. (2) It is possible that the wells could have a net revenue interest to a partnership as low as 84.375% which would reduce the investors' interest to 57.375%. Upper Devonian Sandstone Reservoirs in Armstrong County, Pennsylvania. The managing general partner anticipates the leases in Armstrong County, Pennsylvania will have a net revenue interest to a partnership of 84.375% which would reduce the investors' net revenue interest in the above chart to 57.375% assuming a 100% working interest. U.S. Energy, the originator of the leases, however, will retain a 25% working interest in the wells and participate with the partnership in the costs of drilling, completing, and operating the wells to the extent of its retained working interest. Thus, the net revenue interest to the investors will be reduced to approximately 43% which is 75% of 57.375%. Secondary Areas. Although the managing general partner anticipates each partnership will have a net revenue interest ranging from 81% to 87.5% in the secondary areas described above, there is no minimum net revenue interest that a partnership is required to own before drilling a well in other areas of the Appalachian Basin. The leases in these other areas may be subject to interests in favor of third-parties that are not currently known such as: o overriding royalty interests; o net profits interests; o carried interests; o production payments; o reversionary interests pursuant to farmouts or non-consent elections under joint operating agreements; or o other retained or carried interests. Title to Properties Title to all leases acquired by a partnership will be held in the name of the partnership. However, to facilitate the acquisition of the leases title to the leases may initially be held in the name of: o the managing general partner; o the operator; 60 o their affiliates; or o any nominee designated by the managing general partner. Title to each partnership's leases will be transferred to the partnership and filed for record from time to time after the wells are drilled and completed. The managing general partner will take the steps it deems necessary to assure that each partnership has acceptable title for its purposes. However, it is not the practice in the natural gas and oil industry to warrant title or obtain title insurance on leases and the managing general partner will provide neither for the leases it assigns to a partnership. The managing general partner will obtain a favorable formal title opinion for the leases before each well is drilled, but will not obtain a division order title opinion after the well is completed. The managing general partner may use its own judgment in waiving title requirements and will not be liable for any failure of title of leases transferred to a partnership. Also, there is no assurance that the partnerships will not experience losses from title defects excluded from or not disclosed by the formal title opinion or that would have been disclosed by a division order title opinion. Although past performance is no guarantee of future results, the previous partnerships sponsored by the managing general partner and its affiliates have participated in drilling more than 1,700 wells in the Appalachian Basin since 1985, and none of the wells have been lost because of title failure. (See "Prior Activities.") Drilling and Completion Activities; Operation of Producing Wells The managing general partner intends that Atlas America Public #12-2003 Limited Partnership, which must close on or before December 31, 2003, will drill the prospects described in "Appendix A - Information Regarding Currently Proposed Prospects for Atlas America Public #12-2003 Limited Partnership." These prospects represent a portion of the wells to be drilled if the nonbinding targeted maximum subscription proceeds described in "Terms of the Offering - Subscription to a Partnership,, are received. The managing general partner also anticipates that it will designate a portion of each partnership's prospects in the partnerships designated Atlas America Public #12-2004(___) Limited Partnership by supplement or an amendment to the registration statement. On receipt of the minimum subscriptions and written instructions to the escrow agent from the managing general partner and the dealer-manager, the managing general partner on behalf of a partnership may: o break escrow; o transfer the escrowed funds to a partnership account; o enter into the drilling and operating agreement, which is attached to the partnership agreement as Exhibit II, with itself or an affiliate as operator; and o begin drilling to the extent the prospects have been identified in this prospectus or by supplement or an amendment to the registration statement. Under the drilling and operating agreement, the responsibility for drilling and either completing or plugging partnership wells will be on the managing general partner or an affiliate as the operator and the general drilling contractor. The managing general partner as operator and general drilling contractor must use its best efforts to begin drilling the wells no later than March 30, 2004 for Atlas America Public #12-2003 Limited Partnership, and March 31, 2005 for partnerships designated Atlas America Public #12-2004(___) Limited Partnership. Under the drilling and operating agreement, each partnership is required to prepay the investors' share of the drilling and completion costs of its wells to the managing general partner as the operator. If one or more of a partnership's wells will be drilled in the calendar year after the year in which the advance payment is made, the required advance payment allows the partnership to secure tax benefits of prepaid drilling costs based on a substantial business purpose for the advance payment under the drilling and operating agreement. (See "Material Federal Income Tax Consequences-Drilling Contracts.") During drilling operations the managing general partner's duties as operator and general drilling contractor will include: 61 o making the necessary arrangements for drilling and completing partnership wells and related facilities for which it has responsibility under the drilling and operating agreement; o managing and conducting all field operations in connection with drilling, testing, and equipping the wells; and o making the technical decisions required in drilling and completing the wells. All partnership wells will be drilled to a sufficient depth to test thoroughly the objective geological formation. Under the drilling and operating agreement the managing general partner, as operator and general drilling contractor, will complete each well if there is a reasonable probability of obtaining commercial quantities of natural gas or oil. However, based on its past experience, the managing general partner anticipates that most of the wells drilled in the primary and secondary areas will have to be completed before it can determine the well's productivity. If the managing general partner, as operator and general drilling contractor, determines that a well should not be completed, then the well will be plugged and abandoned. During producing operations the managing general partner's duties, as operator, will include: o managing and conducting all field operations in connection with operating and producing the wells; o making the technical decisions required in operating the wells; and o maintaining the wells, equipment, and facilities in good working order during their useful life. The managing general partner, as operator, will be reimbursed for its direct expenses and will receive well supervision fees at competitive rates for operating and maintaining the wells during producing operations. As discussed in "Summary of Drilling and Operating Agreement", the drilling and operating agreement contains a number of other material provisions which you are urged to review. Certain wells may be drilled with third-parties owning a portion of the working interest in the wells. Any other working interest owner in a well may have a separate agreement with the managing general partner for drilling and operating the well with differing terms and conditions from those contained in a partnership's drilling and operating agreement. Sale of Natural Gas and Oil Production Policy of Treating All Wells Equally in a Geographic Area. The managing general partner is responsible for selling each partnership's natural gas and oil production, and its policy is to treat all wells in a given geographic area equally. This reduces certain potential conflicts of interest among the owners of the various wells, including the partnerships, concerning to whom and at what price the natural gas and oil will be sold. For example, the managing general partner calculates a weighted average selling price for all of the natural gas sold in the geographic area by dividing the money received from the sale of all of the natural gas sold to customers in the area, which may be at different prices, by the volume of all natural gas sold from the wells in the area. For natural gas sold in western Pennsylvania the managing general partner received an average selling price after deducting all expenses, including transportation expenses, of approximately: o $2.22 per mcf in 1998; o $2.35 per mcf in 1999; o $3.30 per mcf in 2000; o $4.08 per mcf in 2001; and 62 o $3.34 per mcf in 2002. Mcf means 1,000 cubic feet of gas. If all the natural gas produced cannot be sold because of limited gathering or pipeline capacity, or limited demand for the natural gas, which increases pipeline pressure, then the production that is sold will be from those wells which have the greatest well pressure and are able to feed into the pipeline, regardless of which partnerships own the wells. The proceeds from these natural gas sales will be credited only to the partnerships whose wells produced the natural gas sold. Gathering of Natural Gas. Under the partnership agreement the managing general partner will be responsible for gathering and transporting the natural gas produced by the partnerships to interstate pipeline systems, local distribution companies, and end-users in the area. For the majority of each partnership's natural gas production, including natural gas in the primary areas, as discussed below, the managing general partner anticipates that it will use the gathering system owned by Atlas Pipeline Partners, L.P. (and Atlas Pipeline Operating Partnership) which is a master limited partnership formed by a subsidiary of Atlas America as managing general partner using Atlas America and Viking Resources personnel who act as its officers and employees. Atlas Pipeline Partners acquired the natural gas gathering system and related facilities of Atlas America, Resource Energy, and Viking Resources in February 2000. The gathering system consists of approximately 1,300 miles of intrastate pipelines located in western Pennsylvania, eastern Ohio, and western New York. If a partnership's natural gas is not transported through the Atlas Pipeline Partners gathering system, it is because there is a third-party operator or the gathering system has not been extended to the wells. In these cases as described in "Compensation - Gathering Fees", the natural gas will be transported through a third-party gathering system, and the partnership will pay the managing general partner a competitive gathering fee all or a portion of which will be paid to the third-party. As a part of the sale of the gathering system to Atlas Pipeline Partners in February 2000, Atlas America and its affiliates, Resource Energy and Viking Resources, made the commitments set forth below which to varying degrees may affect the partnerships. The commitments were intended to maximize the use and expansion of the gathering system. These are continuing obligations of Atlas America, Resource Energy, and Viking Resources. Atlas America, Resource Energy and Viking Resources are required to pay a gathering fee to Atlas Pipeline Partners equal to the greater of $0.35 per mcf or 16% of the gross sales price for each mcf transported through the gathering system of Atlas Pipeline Partners. If a partnership pays a lesser amount, which is anticipated by the managing general partner to range from $.29 per mcf to $.35 per mcf except in the McKean County area as described in "Compensation - Gathering Fees", then Atlas America, Resource Energy or Viking Resources must pay the difference to Atlas Pipeline Partners. Also, Atlas America, Resource Energy and Viking Resources committed to adding 225 wells to the gathering system over a period from January 1, 1999, until December 31, 2002, which included any well drilled in a partnership sponsored by them, which has been satisfied. The wells had to be drilled within 2,500 feet of the gathering system and the partnership as the well owner had to construct up to 2,500 feet of small diameter sales or flow lines from the wellhead to the gathering system. Finally, Atlas America, Resource Energy and Viking Resources agreed to assist Atlas Pipeline Partners in identifying existing gathering systems for possible acquisition and Atlas America agreed to provide construction management and financing services to Atlas Pipeline Partners in the construction of additions or extensions to the gathering system. For a period of five years from January 28, 2000, to January 28, 2005, Atlas America has a standby commitment for a maximum of $1.5 million in any contract year. Natural Gas Contracts. The managing general partner, Resource Energy and Atlas Energy Group, Inc. have a natural gas supply agreement with First Energy Solutions Corporation for a 10-year term which began on April 1, 1999. Subject to certain exceptions, First Energy Solutions Corporation has a last right of refusal to buy all of the natural gas produced and delivered by the managing general partner and its affiliates, which includes the partnerships, at certain delivery points with the facilities of: o East Ohio Gas Company, National Fuel Gas Distribution, Columbia of Ohio, and Peoples Natural Gas Company, which are local distribution companies; and 63 o National Fuel Gas Supply, Columbia Gas Transmission Corporation, Tennessee Gas Pipeline Company, and Texas Eastern Transmission Company, which are interstate pipelines. First Energy Solutions Corporation is the marketing affiliate of First Energy Corporation, which is based in Akron, Ohio and is a large regional electric utility listed on the New York Stock Exchange. First Energy Corporation has provided a guaranty of the monetary obligations of First Energy Solutions Corporation of an amount up to $15 million for a period until March 31, 2005, which will continue on a monthly basis thereafter unless terminated on 30 days notice. The majority of the managing general partner's and its affiliates' natural gas is subject to the agreement with First Energy Solutions Corporation, with the following exceptions: o natural gas being sold to Warren Consolidated, an industrial end-user, and direct delivery customer of the managing general partner and its affiliates; o natural gas that at the time of the agreement was already dedicated for the life of the well to another buyer; o natural gas that is produced by a company which was not an affiliate of the managing general partner at the time of the agreement; o natural gas that is delivered to interstate pipelines or local distribution companies other than those described above; or o natural gas that is produced from well(s) operated by a third-party or subject to an agreement under which a third-party was to arrange for the gathering and sale of the natural gas. Based on the most recent monthly production data available to it as of the date of this prospectus, the managing general partner anticipates that it and its affiliates, including its affiliated partnerships, will sell approximately 60% of their natural gas production under the agreement with First Energy Solutions Corporation. The agreement established an indexed price formula for each of the delivery points during an initial period of one or two years, and requires the parties to negotiate a new pricing arrangement at each delivery point for subsequent periods. If, at the end of any applicable period, the parties cannot agree to a new price for any delivery point, then the managing general partner and its affiliates may solicit offers from third-parties to buy the natural gas for that delivery point. If First Energy Solutions Corporation does not match this price, then the natural gas may be sold to the third-party. This process is repeated at the end of each contract period which is usually one year. For example, during the period April 1, 2000 through March 31, 2001, the managing general partner and its affiliates sold natural gas delivered to National Fuel Gas Supply to other entities under this process. The managing general partner anticipates that the majority of the natural gas produced by each partnership from wells drilled in the primary and secondary areas will be sold to First Energy Solutions Corporation as described above in "-Primary Areas of Operations" and "-Secondary Areas of Operations." For the period from April 1, 2003 through March 31, 2004, the managing general partner and First Energy Solutions Corporation have been able to agree to new pricing arrangements for approximately 75% of the delivery points, which are described above, under their agreement. The remainder of the natural gas, which is primarily located in the Fayette County area, will be marketed primarily to Colonial Energy, Inc. and UGI Energy Services, and possibly others, for the period ending March 31, 2004. The pricing arrangements with First Energy Solutions Corporation and the other third-parties are tied to the New York Mercantile Exchange Commission ("NYMEX") monthly futures contracts price, which is reported daily in the Wall Street Journal. The total price received for each partnership's gas is a combination of the monthly NYMEX futures price plus a fixed basis. For example, the NYMEX futures price is the base price and there is an additional premium paid because of the location of the gas (the Appalachian Basin) in relation to the gas market which is referred to as the basis. See " - Policy of Treating All Wells Equally in a Geographic Area" for the average natural gas prices since 1998. 64 The agreement with First Energy Solutions Corporation may be suspended for force majeure, which means generally such things as an act of God, fire, storm, flood, and explosion, but also includes the permanent closing of the factories of Carbide Graphite or Duferco Farrell Corporation during the term of First Energy Solutions Corporation's agreements to sell natural gas to them. If these factories were closed, however, the managing general partner believes that First Energy Solutions Corporation would be able to find alternative purchasers and would not invoke the force majeure. The marketing of natural gas production has been influenced by the availability of financial instruments that may be used to hedge the price that will ultimately be paid for future deliveries of natural gas. The managing general partner purchases and sells natural gas futures and options contracts to limit its and its partnerships' exposure to changes in natural gas prices. These contracts may include regulated NYMEX futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. The futures contracts employed by the managing general partner are commitments to purchase or sell natural gas at future dates and generally cover one-month periods for up to 24 months in the future. To assure that the financial instruments will be used solely for hedging price risks and not for speculative purposes, the managing general partner has established a committee to assure that all financial trading is done in compliance with the managing general partner's hedging policies and procedures. The managing general partner does not intend to contract for positions that it cannot offset with actual production. Although hedging provides the partnerships some protection against falling prices, these activities also could reduce the potential benefits of price increases, depending on the instrument. First Energy Solutions Corporation and the third-party marketers, such as Colonial Energy, Inc. and UGI Energy Services, also use NYMEX based financial instruments to hedge their pricing exposure and make price hedging opportunities available to the managing general partner. These transactions are similar to NYMEX based futures contracts, swaps and options, but also require firm delivery of the hedged quantity. Thus, the managing general partner limits these arrangements to much smaller quantities than those projected to be available at any delivery point. The price paid by First Energy Solutions Corporation, Colonial Energy, Inc., UGI Energy Services, and any other third-party marketers for certain volumes of natural gas sold under these hedge agreements may be significantly different from the underlying monthly spot market value. The portion of natural gas that is hedged and the manner in which it is hedged (e.g. fixed pricing, floor and/or costless collar pricing (i.e. a floor price with a cap), etc.) changes from time to time. As of August 1, 2003, the managing general partner's overall price hedging position for the future months ending July 31, 2004 was approximately as follows: o 48.2% was hedged with a fixed price; o 9.2% was hedged with a floor price and/or costless collar price; and o 42.6% was not hedged and was subject to market based pricing. Approximately 73.7% of these hedges were implemented through First Energy Solutions. It is difficult to project what portion of these hedges will be allocated to each partnership by the managing general partner because of uncertainty about the quantity, timing, and delivery locations of natural gas that may be produced by a partnership. Marketing of Natural Gas Production from Wells in Other Areas of the United States. The managing general partner expects that natural gas produced from wells drilled in areas of the Appalachian Basin other than described above, will be primarily tied to the spot market price and supplied to: o gas marketers; o local distribution companies; o industrial or other end-users; and/or o companies generating electricity. 65 Crude Oil. Crude oil produced from the wells will flow directly into storage tanks where it will be picked up by the oil company, a common carrier, or pipeline companies acting for the oil company which is purchasing the crude oil. Unlike natural gas, crude oil does not present any transportation problem. The managing general partner anticipates selling any oil produced by the wells to regional oil refining companies at the prevailing spot market price for Appalachian crude oil in spot sales. The managing general partner was receiving an average selling price for oil of approximately: o $13.00 per barrel in 1998; o $16.20 per barrel in 1999; o $26.21 per barrel in 2000; o $22.60 per barrel in 2001; and o $18.92 per barrel in 2002. Over the past eight years, the price of oil has ranged from approximately $38 to as low as $8 per barrel. There can be no assurance as to the price of oil during the term of the partnerships. Insurance Since 1972 the managing general partner and its affiliates, including its partnerships, have been involved in the drilling of approximately 4,975 wells in Ohio, Pennsylvania, and other areas of the Appalachian Basin. They have not incurred a blow-out or made any material insurance claims with any of these wells. See "Actions to be Taken by Managing General Partner to Reduce Risks of Additional Payments by Investor General Partners - Insurance" for a discussion of the insurance coverage. Use of Consultants and Subcontractors The partnership agreement authorizes the managing general partner to use the services of independent outside consultants and subcontractors on behalf of the partnerships. The services will normally be paid on a per diem or other cash fee basis and will be charged to the partnership on whose behalf the costs were incurred as either a direct cost or as a direct expense under the drilling and operating agreement. These charges will be in addition to the unaccountable, fixed payment reimbursement paid to the managing general partner for administrative costs and well supervision fees paid to the managing general partner as operator. COMPETITION, MARKETS AND REGULATION Natural Gas Regulation Governmental agencies regulate the production and transportation of natural gas. Generally, the regulatory agency in the state where a producing natural gas well is located supervises production activities and the transportation of natural gas sold into intrastate markets, and the Federal Energy Regulatory Commission ("FERC") regulates the interstate transportation of natural gas. Natural gas prices are not regulated, and the price of natural gas is subject to the supply and demand for the natural gas along with factors such as the natural gas' BTU content and where the wells are located. See "- Competition and Markets" below for certain measures which FERC has taken to increase competitiveness in the natural gas markets. Crude Oil Regulation Oil prices are not regulated, and the price is subject to the supply and demand for oil, along with qualitative factors such as the gravity of the crude oil and sulfur content differentials. 66 Competition and Markets There are many companies engaged in natural gas and oil drilling operations in the Appalachian Basin, where all of the wells in each partnership will be located. According to the Energy Information Administration, the independent statistical and analytical agency within the Department of Energy, the Appalachian Basin accounted for 3.5% of the total domestic natural gas production in the year 2000 in the United States, and as of December 31, 2000 it held economically recoverable reserves representing approximately 4.5% of total domestic reserves. The oil and gas industry is highly competitive in all phases, including acquiring suitable properties for drilling and marketing natural gas and oil. Product availability and price are the principal means of competing in selling natural gas and oil. Many of the partnerships' competitors will have financial resources and staffs larger than those available to the partnerships. While it is impossible to accurately determine the partnerships' industry position, the managing general partner does not consider the partnerships' operations to be a significant factor in the industry. Current economic conditions indicate that the costs of exploration and development are increasing gradually. However, the natural gas and oil industry has from time to time experienced periods of rapid cost increases. Over the term of a partnership there may be fluctuating or increasing costs in doing business which directly affect the managing general partner's ability to operate the partnership's wells at acceptable price levels. Also, the natural gas price increases which occurred at the end of 2002 and the beginning of 2003 may increase the demand for drilling rigs and other related equipment. This may increase the cost to drill the wells or reduce the availability of drilling rigs and related equipment, both of which could adversely affect the partnerships. The natural gas and oil produced by your partnership's wells must be marketed for you to receive revenues. As set forth above, natural gas and oil prices are not regulated, but instead are subject to factors which are primarily beyond the partnership's control such as the supply and demand for the natural gas and oil. For example, reduced natural gas demand and/or excess natural gas supplies will result in lower prices, and in recent years natural gas and oil prices have been volatile. Other factors affecting the marketing of natural gas and oil production, which are also beyond the control of the partnerships and cannot be accurately predicted, are the following: o the proximity, availability, and capacity of pipeline and other transportation facilities; o competition from other energy sources such as coal and nuclear energy; o local, state, and federal regulations regarding production and transportation; o the general level of market demand on a regional, national and worldwide basis; o fluctuating seasonal supply and demand because of various factors such as home heating requirements in the winter months; o political instability and/or war in natural gas and oil producing countries; o the amount of domestic production; and o the amount of foreign imports of natural gas and oil. For example, increased imports into the United States of Canadian natural gas have occurred and are expected to continue which will increase the supply of natural gas in the United States. This increase in natural gas imports was primarily the result of the North American Free Trade Agreement ("NAFTA"), which eliminated trade and investment barriers in the United States, Canada, and Mexico, and new pipeline projects that have been constructed and/or proposed to the FERC. Without a corresponding increase in demand in the United States, the imported natural gas would have an adverse effect on both the price and volume of natural gas sales from the partnerships' wells. However, according to the Energy Information 67 Administration, the use of natural gas in the United States is projected to increase approximately 51% to 69% between 1999 and 2020. Also, members of the Organization of Petroleum Exporting Countries ("OPEC") establish production quotas for petroleum products from time to time with the intent of increasing, maintaining, or decreasing price levels. The managing general partner, however, is unable to predict what effect these actions will have on the price of the natural gas and oil sold from the partnerships' wells. FERC has sought to promote greater competition in natural gas markets in the U.S. Traditionally, natural gas was sold by producers to interstate pipeline companies that resold the natural gas to local distribution companies for resale to end-users. FERC changed this market structure by requiring interstate pipeline companies to transport natural gas for third-parties. Thereafter, FERC Order 636 was issued which requires pipeline companies to, among other things, separate their sales services from their transportation services and provide an open access transportation service that is comparable in quality for all natural gas producers or suppliers. The premise behind FERC Order 636 was that the interstate pipeline companies had an unfair advantage over other natural gas producers or suppliers because they could bundle their sales and transportation services together. FERC Order 636 is designed to ensure that no natural gas seller has a competitive advantage over another natural gas seller because it also provides transportation services. In February, 2000, FERC Order 637 was issued to provide further competitive initiatives by removing price ceilings on short-term capacity release transactions. It also enacted other regulatory policies that are intended to increase the flexibility of interstate natural gas transportation. Further, FERC has required pipeline companies to develop electronic bulletin boards to provide standardized access to information concerning capacity and prices. There have been several developments which the managing general partner believes have the effect of increasing the demand for natural gas. For example, the Clean Air Act Amendments of 1990 contain incentives for the future development of "clean alternative fuel," which includes natural gas and liquefied petroleum gas for "clean-fuel vehicles." Also, the accelerating deregulation of electricity transmission has caused a convergence between the natural gas and electricity industries. The electricity industry has increased its reliance on natural gas because of increased competition in the electricity industry and the enforcement of stringent environmental regulations. For example, to reduce urban smog the Environmental Protection Agency has sought to enforce environmental regulations which increase the cost of operating coal-fired power plants, which in December 2000 produced more than half of the U.S.'s electricity. The Department of Energy has also denied financial incentives to utilities to build more nuclear power plants and large scale hydroelectric projects. Together, these policies tend to make natural gas the fuel of choice for electricity producers which have started moving away from dirtier-burning fuels, such as coal and oil. The electricity industry has started plans to bring new natural gas-fired power plants into service, some of which are not designed to allow for switching to other fuels. Natural gas was used to generate approximately 16% of the United States' electricity in December 2000, and this demand is expected to increase through the decade. State Regulations Oil and gas operations are regulated in Pennsylvania by the Department of Environmental Resources. Pennsylvania and the other states where each partnership's wells may be situated impose a comprehensive statutory and regulatory scheme for natural gas and oil operations, including supervising the production activities and the transportation of natural gas sold in intrastate markets, which creates additional financial and operational burdens. Among other things, these regulations involve: o new well permit and well registration requirements, procedures, and fees; o minimum well spacing requirements; o restrictions on well locations and underground gas storage; o certain well site restoration, groundwater protection, and safety measures; 68 o landowner notification requirements; o certain bonding or other security measures; o various reporting requirements; and o well plugging standards and procedures. These state regulatory agencies also have broad regulatory and enforcement powers including those associated with pollution and environmental control laws, which are discussed below. Environmental Regulation Each partnership's drilling and producing operations are subject to various federal, state, and local laws covering the discharge of materials into the environment, or otherwise relating to the protection of the environment. The Environmental Protection Agency and state and local agencies will require the partnerships to obtain permits and take other measures with respect to: o the discharge of pollutants into navigable waters; o disposal of wastewater; and o air pollutant emissions. If these requirements or permits are violated there can be substantial civil and criminal penalties which will increase if there was willful negligence or misconduct. Also, the partnerships may be subject to fines, penalties and unlimited liability for cleanup costs under various federal laws such as the Federal Clean Water Act, the Clean Air Act, the Resource Conservation and Recovery Act, the Oil Pollution Act of 1990, the Toxic Substance Control Act and the Comprehensive Environmental Response, Compensation and Liability Act of 1980 for oil and/or hazardous substance contamination or other pollution caused by the drilling activities or the well and its production. A partnership's liability also can extend to pollution costs that occurred on the leases before they were acquired by the partnership. Although the managing general partner will not transfer any lease to a partnership if it has actual knowledge that there is an existing potential environmental liability on the lease, there will not be an independent environmental audit of the leases before they are transferred to a partnership. Thus, there is a risk that the leases will have potential environmental liability even before drilling begins. A partnership's required compliance with these environmental laws and regulations may cause delays or increase the cost of the partnership's drilling and producing activities. Because these laws and regulations are constantly being revised and changed, the managing general partner is unable to predict the ultimate costs of complying with present and future environmental laws and regulations. Also, the managing general partner is unable to obtain insurance to protect against many environmental claims. Proposed Regulation From time to time there are a number of proposals considered in Congress and in the legislatures and agencies of various states that if enacted would significantly and adversely affect the natural gas and oil industry and the partnerships. The proposals involve, among other things: o limiting the disposal of waste water from wells that could substantially increase a partnership's operating costs and make the partnership's wells uneconomical to produce; and o changes in the tax laws as discussed in "Material Federal Income Tax Consequences-Changes in the Law." 69 However, it is impossible to accurately predict what proposals, if any, will be enacted and their subsequent effect on a partnership's activities. PARTICIPATION IN COSTS AND REVENUES In General The partnership agreement provides for the sharing of costs and revenues among the managing general partner and you and the other investors. A tabular summary of the following discussion appears below. Each partnership will be a separate business entity from the other partnerships, and you will be a partner only in the partnership in which you invest. You will have no interest in the business, assets, or tax benefits of the other partnerships unless you also invest in the other partnerships. Thus, your investment return will depend solely on the operations and success or lack of success of the particular partnership in which you invest. Costs 1. Organization and Offering Costs. Organization and offering costs will be charged 100% to the managing general partner. However, the managing general partner will not receive any credit towards its required capital contribution or its revenue share for any organization and offering costs charged to it in excess of 15% of a partnership's investors' subscription proceeds. o Organization and offering costs generally means all costs of organizing and selling the offering and includes the dealer-manager fee, sales commissions, the .5% reimbursement for bona fide accountable due diligence expenses, and the .5% accountable marketing expense fee. The managing general partner will pay a portion of the organization and offering costs to itself, its affiliates and third-parties and it will contribute the remainder to the partnership in the form of services related to organizing this offering. The managing general partner will receive a credit for these payments and services towards its required capital contribution in each partnership. The managing general partner's credit for its contribution of services for organization costs will be determined based on generally accepted accounting principles. The definition of organization and offering costs is set forth in the partnership agreement. 2. Lease Costs. Each partnership's leases will be contributed by the managing general partner. The managing general partner will be credited with a capital contribution for each lease valued at: o its cost; or o fair market value if the managing general partner has reason to believe that cost is materially more than fair market value. 3. Intangible Drilling Costs. Intangible drilling costs of your partnership will be charged 100% to you and the other investors. o Intangible drilling costs generally means those costs of drilling and completing a well that are currently deductible, as compared with lease costs, which must be recovered through the depletion allowance, and equipment costs, which must be recovered through depreciation deductions. Although subscription proceeds of a partnership may be used to pay the costs of drilling different wells depending on when the subscriptions are received, not less than 90% of the subscription proceeds of you and the other investors will be used to pay intangible drilling costs regardless of when you subscribe. Also, even if the IRS successfully challenged the managing general partner's characterization of a portion of these costs as deductible intangible drilling costs, and instead recharacterized the costs as some other item that may be non-deductible, such as equipment costs and/or lease costs, this 70 recharacterization by the IRS would have no effect on the allocation and payment of the costs by you and the other investors under the partnership agreement. 4. Equipment Costs. Equipment costs of your partnership will be charged 66% to the managing general partner and 34% to you and the other investors. However, if the total equipment costs for your partnership's wells that would be charged to you and the other investors exceeds an amount equal to 10% of the subscription proceeds of you and the other investors in the partnership, then the excess will be charged to the managing general partner. o Equipment costs generally means the costs of drilling and completing a well that are not currently deductible and are not lease costs. 5. Operating Costs, Direct Costs, Administrative Costs and All Other Costs. Operating costs, direct costs, administrative costs, and all other partnership costs of your partnership not specifically charged will be charged to the parties in the same ratio as the related production revenues are being credited. o These costs generally include all costs of partnership administration and producing and maintaining the partnership's wells. 6. The Managing General Partner's Required Capital Contribution. The managing general partner's aggregate capital contributions to each partnership must not be less than 25% of all capital contributions to that partnership. This includes such items as: o its credit for the cost of the leases contributed to the partnership; o its credit for organization and offering costs, including the costs of services contributed as organization costs; and o its share of partnership equipment costs paid by it to itself as operator under the drilling and operating agreement, which includes its administrative overhead reimbursement and profit on those costs. The managing general partner's capital contributions must be paid or made at the time the costs are required to be paid by the partnership, but not later than the end of the year immediately following the year in which the partnership had its final closing. Revenues Each partnership's production revenues from all of its wells will be commingled. Thus, regardless of when you subscribe to a partnership you will share in the production revenues from all wells in that partnership on the same basis as the other investors in the partnership in proportion to your number of units. 1. Proceeds from the Sale of Leases. If a partnership well is sold, a portion of the sales proceeds will be allocated to the partners in the same proportion as their share of the adjusted tax basis of the property. In addition, proceeds will be allocated to the managing general partner to the extent of the pre-contribution appreciation in value of the property, if any. Any excess will be credited as provided in 4, below. 2. Interest Proceeds. Interest income will be shared as follows: o interest earned on your subscription proceeds before the final closing of your partnership will be credited to your account and paid not later than the partnership's first cash distributions from operations; 71 o after the final closing of your partnership and until the subscription proceeds from the closing are invested in your partnership's operations any interest income from temporary investments will be allocated pro rata to you and the other investors providing the subscription proceeds; and o all other interest income, including interest earned on the deposit of production revenues, will be credited as provided in 4, below. 3. Equipment Proceeds. Proceeds from the sale or other disposition of equipment will be credited to the parties charged with the costs of the equipment in the ratio in which the costs were charged. 4. Production Revenues. Subject to the managing general partner's subordination obligation as described below, the managing general partner and the investors in a partnership will share in all of that partnership's other revenues, including production revenues, in the same percentage as their respective capital contribution bears to the total partnership capital contributions, except that the managing general partner will receive an additional 7% of that partnership's revenues. However, the managing general partner's total revenue share may not exceed 35% of that partnership's revenues regardless of the amount of its capital contributions. For example, if the managing general partner contributes the minimum of 25% of the total partnership capital contributions and the investors contribute 75% of the total partnership capital contributions, then the managing general partner will receive 32% of the partnership revenues and the investors will receive 68% of the partnership revenues. On the other hand, if the managing general partner contributes 30% of the total partnership capital contributions and the investors contribute 70% of the total partnership capital contributions, then the managing general partner will receive 35% of the partnership revenues, not 37%, because its revenue share cannot exceed 35% of partnership revenues, and the investors will receive 65% of partnership revenues. Subordination of Portion of Managing General Partner's Net Revenue Share Each partnership is structured to provide you and the other investors with cash distributions equal to a minimum of 10% per unit, based on $10,000 per unit regardless of the actual subscription price for your units, in each of the first five 12-month periods beginning with that partnership's first cash distributions from operations. To help achieve this investment feature, the managing general partner will subordinate up to 50% of its share of the managing general partner's share of partnership net production revenues during this subordination period. o Partnership net production revenues means gross revenues after deduction of the related operating costs, direct costs, administrative costs, and all other costs not specifically allocated. Each partnership's 60-month subordination period will begin with that partnership's first cash distribution from operations to you and the other investors. However, no subordination distributions to you and the other investors will be required until that partnership's first cash distribution after substantially all of the partnership wells are drilled, completed, and begin producing into a sales line. Subordination distributions will be determined by debiting or crediting current period partnership revenues to the managing general partner as may be necessary to provide the distributions to you and the other investors. At any time during the subordination period the managing general partner is entitled to an additional share of partnership revenues to recoup previous subordination distributions to the extent your cash distributions from that partnership exceed the 10% return described above. The specific formula is set forth in Section 5.01(b)(4)(a) of the partnership agreement. The managing general partner anticipates you will benefit from the subordination if the price of natural gas and oil received by the partnership and/or the results of the partnership's drilling activities are unable to provide the required return. However, if the wells produce small natural gas and oil volumes or natural gas and oil prices decrease, then even with subordination your cash flow may be very small and you may not receive the 10% return for each of the first five years beginning with the partnership's first cash distribution from operations. 72 As of May 15, 2003, the managing general partner was subordinating a portion or all of its net revenues in 3 of its previous 12 limited partnerships that currently have the subordination feature in effect. Since 1993 the managing general partner has had a subordination feature in 23 of its partnerships and from time to time it has subordinated its partnership net revenues in 16 of these partnerships. The managing general partner is entitled to recoup these subordination distributions during the subordination period to the extent cash distributions to the investors in these previous partnerships would exceed the specified return to the investors. Example of Net Revenue Sharing During a Subordination Period.
Net Revenues to Managing Maximum Amount of General Partner and Managing General Investors if Maximum Amount Percentage of Percentage of Partner's Share of of Managing General Partnership Partnership Net Partnership Net Partner's Share of Capital Revenues Without Revenues Available for Partnership Net Revenues is Entity Contributions (1) Subordination (1) Subordination (2) Subordinated (1)(2) - ------ ----------------- ----------------- ---------------------- ---------------------------- Managing General Partner................25% 32% 16% 16% Investors...............................75% 68% 84%
- -------------------------------- (1) These percentages are for illustration purposes only and assume the managing general partner's minimum required capital contribution of 25% to each partnership and capital contributions of 75% from you and the other investors. The actual percentages are likely to be different because they will be based on the actual capital contributions of the managing general partner and you and the other investors. However, the managing general partner's total revenue share may not exceed 35% of partnership revenues regardless of the amount of its capital contribution. (2) Each partnership is structured to provide you and the other investors with cash distributions equal to a minimum of 10% per unit, based on $10,000 per unit regardless of the actual subscription price for your units, in each of the first five 12-month periods beginning with the partnership's first cash distributions from operations. To help achieve this investment feature, the managing general partner will subordinate up to 50% of its share of partnership net production revenues during this subordination period. Example of Net Revenue Sharing After the End of a Subordination Period.
Net Revenues to Managing Maximum Amount of General Partner and Managing General Investors if Maximum Amount Percentage of Percentage of Partner's Share of of Managing General Partnership Partnership Net Partnership Net Partner's Share of Capital Revenues Without Revenues Available for Partnership Net Revenues is Entity Contributions (1) Subordination (1) Subordination Subordinated (1) - ------ ----------------- ----------------- ---------------------- --------------------------- Managing General Partner.................25% 32% 0% 32% Investors................................75% 68% 68%
- ------------------------------------- (1) These percentages are for illustration purposes only and assume the managing general partner's minimum required capital contribution of 25% to each partnership and capital contributions of 75% from you and the other investors. The actual percentages are likely to be different because they will be based on the actual capital contributions of the managing general partner and you and the other investors. However, the managing general partner's total revenue share may not exceed 35% of partnership revenues regardless of the amount of its capital contribution. Table of Participation in Costs and Revenues The following table sets forth the partnership costs and revenues charged and credited between the managing general partner and you and the other investors in each partnership after deducting from the partnership's gross revenues the landowner royalties and any other lease burdens. 73
Managing General Partner Investors ------------------ ------------------ Partnership Costs Organization and offering costs 100% 0% Lease costs 100% 0% Intangible drilling costs 0% 100% Equipment costs (1) 66% 34% Operating costs, administrative costs, direct costs, and all other costs (2) (2) Partnership Revenues Interest income (3) (3) Equipment proceeds (1) 66% 34% All other revenues including production revenues (4)(5) (4)(5) Participation in Deductions Intangible drilling costs 0% 100% Depreciation (1) 66% 34% Percentage depletion allowance (4)(5)(6) (4)(5)(6)
- --------------- (1) These percentages may vary. If the total equipment costs for all of the partnership's wells that would be charged to you and the other investors exceeds an amount equal to 10% of the subscription proceeds of you and the other investors in the partnership, then the excess will be charged to the managing general partner. Equipment proceeds, if any, will be credited in the same percentage in which the equipment costs were charged. (2) These costs will be charged to the parties in the same ratio as the related production revenues are being credited. (3) Interest earned on your subscription proceeds before the offering of a partnership closes will be credited to your account and paid not later than the partnership's first cash distributions from operations. After the offering closes and until proceeds from the offering are invested in the partnership's operations any interest income from temporary investments will be allocated pro rata to the investors providing the subscription proceeds. All other interest income in the partnership, including interest earned on the deposit of operating revenues, will be credited as production revenues are credited. (4) In each partnership the managing general partner and the investors will share in all of the partnership's other revenues in the same percentage as their respective capital contributions bears to the total partnership capital contributions except that the managing general partner will receive an additional 7% of the partnership revenues. However, the managing general partner's total revenue share in a partnership may not exceed 35% of partnership revenues. (5) If a portion of the managing general partner's partnership net production revenues is subordinated, then the actual allocation of partnership revenues between the managing general partner and the investors will vary from the allocation described in (4) above. (6) The percentage depletion allowances will be in the same percentages as the production revenues. Allocation and Adjustment Among Investors The investors' share as a group of each partnership's revenues, gains, income, costs, expenses, losses, and other charges and liabilities generally will be charged and credited among you and the other investors in that partnership in accordance with your respective number of units, based on $10,000 per unit regardless of the actual subscription price for an investor's units. These allocations will take into account any investor general partner's status as a defaulting investor general partner. Certain investors, however, will pay a reduced amount for their units as described in "Plan of Distribution." Thus, the following 74 costs will be charged among you and the other investors in a partnership in accordance with the respective subscription price you and the other investors paid for the units rather than the number of each investor's units: o intangible drilling costs; and o the investors' share of the equipment costs of drilling and completing the partnership's wells. Distributions The managing general partner will review each partnership's accounts at least quarterly to determine whether cash distributions are appropriate and the amount to be distributed, if any, taking into account its subordination obligation discussed above in "-Subordination of Portion of Managing General Partner's Net Revenue Share." Your partnership will distribute funds to you and the other investors that the managing general partner, in its sole discretion, does not believe are necessary for the partnership to retain. Distributions may be reduced or deferred to the extent partnership revenues are used for any of the following: o repayment of borrowings; o cost overruns; o remedial work to improve a well's producing capability; o direct costs and general and administrative expenses of the partnership; o reserves, including a reserve for the estimated costs of eventually plugging and abandoning the wells; or o indemnification of the managing general partner and its affiliates by the partnership for losses or liabilities incurred in connection with the partnership's activities. Also, funds will not be advanced or borrowed for distributions if the distribution amount would exceed the partnership's accrued and received revenues for the previous four quarters, less paid and accrued operating costs with respect to the revenues. Any cash distributions from a partnership to the managing general partner will be made only in conjunction with distributions to you and the other investors in that partnership and only out of funds properly allocated to the managing general partner's account. Liquidation Each partnership will continue for 50 years unless it is terminated earlier by a final terminating event as described below, or an event which causes the dissolution of a limited partnership under the Delaware Revised Uniform Limited Partnership Act. However, if a partnership terminates on an event which causes a dissolution under state law and it is not a final terminating event, then a successor limited partnership will automatically be formed. Thus, only on a final terminating event will a partnership be liquidated. A final terminating event is any of the following: o the election to terminate the partnership by the managing general partner or the affirmative vote of investors whose units equal a majority of the total units; o the termination of the partnership under Section 708(b)(1)(A) of the Internal Revenue Code because no part of its business is being carried on; or o the partnership ceases to be a going concern. On the partnership's liquidation you will receive your interest in the partnership to which you subscribed. Generally, your interest in the partnership means an undivided interest in the partnership assets, after payments to the partnership's creditors, 75 in the ratio your capital account bears to all the capital accounts until they have been reduced to zero. Thereafter, your interest in the remaining partnership assets will equal your interest in the related partnership revenues. Any in-kind property distributions to you from a partnership must be made to a liquidating trust or similar entity, unless you affirmatively consent to receive an in-kind property distribution after being told of the risks associated with the direct ownership or there are alternative arrangements in place which assure that you will not be responsible for the operation or disposition of the partnership properties. If the managing general partner has not received your written consent to the in-kind distribution within 30 days after it is mailed, then it will be presumed that you have not consented. The managing general partner may then sell the asset at the best price reasonably obtainable from an independent third-party, or to itself or its affiliates at fair market value as determined by an independent expert selected by the managing general partner. Also, if a partnership is liquidated, the managing general partner will be repaid for any debts owed it by the partnership before there are any payments to you and the other investors in that partnership. CONFLICTS OF INTEREST In General Conflicts of interest are inherent in natural gas and oil partnerships involving non-industry investors because the transactions are entered into without arms' length negotiation. Your interests and those of the managing general partner and its affiliates may be inconsistent in some respects or in certain instances, and the managing general partner's actions may not be the most advantageous to you. The following discussion describes certain possible conflicts of interest that may arise for the managing general partner and its affiliates in the course of each partnership. For some of the conflicts of interest, but not all, there are certain limitations on the managing general partner that are designed to reduce, but which will not eliminate, the conflicts. Other than these limitations the managing general partner has no procedures to resolve a conflict of interest and under the terms of the partnership agreement the managing general partner may resolve the conflict of interest in its sole discretion and best interest. The following discussion is materially complete; however, other transactions or dealings may arise in the future that could result in conflicts of interest for the managing general partner and its affiliates. Conflicts Regarding Transactions with the Managing General Partner and its Affiliates Although the managing general partner believes that the compensation and reimbursement that it and its affiliates will receive in connection with each partnership are reasonable, the compensation has been determined solely by the managing general partner and did not result from negotiations with any unaffiliated third-party dealing at arms' length. The managing general partner and its affiliates will receive compensation and reimbursement from each partnership for their services in drilling, completing, and operating that partnership's wells under the drilling and operating agreement and will receive the other fees described in "Compensation" regardless of the success of that partnership's wells. The managing general partner and its affiliates providing the services or equipment can be expected to profit from the transactions, and it is usually in the managing general partner's best interest to enter into contracts with itself and its affiliates rather than unaffiliated third-parties even if the contract terms, skill, and experience, offered by the unaffiliated third-parties is comparable. The partnership agreement provides that when the managing general partner and any affiliate provide services or equipment to a partnership their fees must be competitive with the fees charged by unaffiliated third-parties in the same geographic area engaged in similar businesses. Also, before the managing general partner and any affiliate may receive competitive fees for providing services or equipment to a partnership they must be engaged, independently of the partnership and as an ordinary and ongoing business, in rendering the services or selling or leasing the equipment and supplies to a substantial extent to other persons in the natural gas and oil industry in addition to the partnerships in which the managing general partner or an affiliate has an interest. If the managing general partner and any affiliate is not engaged in such a business, then the compensation must be the lesser of its cost or the competitive rate that could be obtained in the area. 76 Any services not otherwise described in this prospectus or the partnership agreement for which the managing general partner or an affiliate is to be compensated by a partnership must be: o set forth in a written contract that describes the services to be rendered and the compensation to be paid; and o cancelable without penalty on 60 days written notice by investors whose units equal a majority of the total units. The compensation, if any, will be reported to you in your partnership's annual and semiannual reports, and a copy of the contract will be provided to you on request. There is also a conflict of interest concerning the purchase price if the managing general partner or an affiliate purchases a property from a partnership, which they may do in certain limited circumstances as described in "- Conflicts Involving the Acquisition of Leases - (6) Limitations on Sale of Undeveloped and Developed Leases to the Managing General Partner", below. Conflict Regarding the Drilling and Operating Agreement The managing general partner anticipates that all of the wells drilled by each partnership will be drilled and operated under the drilling and operating agreement. This creates a continuing conflict of interest because the managing general partner must monitor and enforce, on behalf of each partnership, its own compliance with the drilling and operating agreement. Conflicts Regarding Sharing of Costs and Revenues The managing general partner will receive a percentage of revenues greater than the percentage of costs that it pays. This sharing arrangement may create a conflict of interest between the managing general partner and you and the other investors in a partnership concerning the determination of which wells will be drilled by the partnership based on the risk and profit potential associated with the wells. In addition, the allocation of all the intangible drilling costs to you and the other investors and the majority of the equipment costs to the managing general partner creates a conflict of interest between the managing general partner and you and the other investors concerning whether to complete a well. For example, the completion of a marginally productive well might prove beneficial to you and the other investors, but not to the managing general partner. When a completion decision is made you and the other investors will have already paid the majority of your costs so you will want to pay your share of the additional costs to complete the well only if there is a reasonable opportunity to recoup your completion costs plus any portion of the costs paid by you before the completion attempt. However, if it appears likely that you would not recoup all of the additional costs to complete the well, you will want to plug the well. On the other hand, the managing general partner will have paid only a portion of its costs before this time, and it will want to pay its additional equipment costs to complete the well only if it is reasonably certain of recouping its money and making a profit. However, based on its past experience the managing general partner anticipates that most of the wells in the primary areas will have to be completed before it can determine the well's productivity, which would eliminate this potential conflict of interest. In any event, the managing general partner will not cause any well to be plugged and abandoned without a completion attempt unless it makes the decision in accordance with generally accepted oil and gas field practices in the geographic area of the well location. Conflicts Regarding Tax Matters Partner The managing general partner will serve as each partnership's tax matters partner and represent the partnership before the IRS. The managing general partner will have broad authority to act on behalf of you and the other investors in the partnership in any administrative or judicial proceeding involving the IRS, and this authority may involve conflicts of interest. For example, potential conflicts include: o whether or not to expend partnership funds to contest a proposed adjustment by the IRS, if any, to: 77 o the amount of a partnership's deduction for intangible drilling costs, which is allocated 100% to you and the other investors in the partnership; or o the amount of the managing general partner's depreciation deductions, or the credit to its capital account for contributing the leases to a partnership, which would decrease the managing general partner's liquidation interest in the partnership; or o the amount of the managing general partner's reimbursement from a partnership for expenses incurred by it in its role as the tax matters partner. Conflicts Regarding Other Activities of the Managing General Partner, the Operator and Their Affiliates The managing general partner will be required to devote to each partnership the time and attention that it considers necessary for the proper management of the partnership's activities. However, the managing general partner has sponsored and continues to manage other natural gas and oil drilling partnerships, which may be concurrent, and will engage in unrelated business activities, either for its own account or on behalf of other partnerships, joint ventures, corporations, or other entities in which it has an interest. This creates a continuing conflict of interest in allocating management time, services, and other activities among the partnerships of this program and its other activities. The managing general partner will determine the allocation of its management time, services, and other functions on an as-needed basis consistent with its fiduciary duties among the partnerships of this program and its other activities. Subject to its fiduciary duties, the managing general partner will not be restricted from participating in other businesses or activities, even if these other businesses or activities compete with a partnership's activities and operate in the same areas as the partnership. However, the managing general partner and its affiliates may pursue business opportunities that are consistent with the partnership's investment objectives for their own account only after they have determined that the opportunity either: o cannot be pursued by the partnership because of insufficient funds; or o it is not appropriate for the partnership under the existing circumstances. Conflicts Involving the Acquisition of Leases The managing general partner will select, in its sole discretion, the wells to be drilled by each partnership. Conflicts of interest may arise concerning which wells will be drilled by each partnership in this program and which wells will be drilled by the managing general partner's and its affiliates' other affiliated partnerships or third-party programs in which they serve as driller/operator. It may be in the managing general partner's or its affiliates' advantage to have a partnership in this program bear the costs and risks of drilling a particular well rather than another affiliate. These potential conflicts of interest will be increased if the managing general partner organizes and allocates wells to more than one partnership at a time. To lessen this conflict of interest the managing general partner generally takes a similar interest in other partnerships when it serves as managing general partner and/or driller/operator. The managing general partner anticipates that generally only one partnership will be actively engaged in drilling at any time. However, when the managing general partner must provide prospects to two or more partnerships at the same time it will attempt to treat each partnership fairly on a basis consistent with: o the funds available to the partnerships; and o the time limitations on the investment of funds for the partnerships. Generally, the managing general partner follows a policy of developing prospects in the order of what it believes is the "best available prospect." However, the managing general partner will constantly change its assessment of available prospects based on the acquisition of new leases and information derived from wells already drilled. 78 If more than one partnership in this program has funds available for drilling at the same time, the partnerships will alternate drilling of wells based on the "best available prospect" format. The determination of the "best available prospect" is based on the managing general partner's assessment of the economic potential of a prospect and its suitability to a particular partnership, including the following factors: o estimated reserves; o the targeted geological formations; o gas and oil markets; o geological and gas and oil market diversification within the partnerships; o the prospect's net revenue interest; o estimated drilling costs; and o limitations imposed by the prospectus and/or the partnership agreement. The partnership agreement gives the managing general partner the authority to cause each partnership in this program to acquire undivided interests in natural gas and oil properties, and to participate with other parties, including other drilling programs previously or subsequently conducted by the managing general partner or its affiliates, in the conduct of its drilling operations on those properties. If conflicts between the interest of a partnership in this program and other drilling partnerships do arise, then the managing general partner may be unable to resolve those conflicts to the maximum advantage of the partnership in this program because the managing general partner must deal fairly with the investors in all of its drilling partnerships. In addition, subject to the restrictions set forth below, the managing general partner decides which prospects and what interest to transfer to a partnership. This will result in a subsequent partnership sponsored by the managing general partner benefitting from knowledge gained through a prior partnership's drilling experience in an area and acquiring a prospect adjacent to the prior partnership's prospect. No procedures, other than the guidelines set forth below and in " - Procedures to Reduce Conflicts of Interest", have been established by the managing general partner to resolve any conflicts that may arise. The partnership agreement provides that the managing general partner and its affiliates will abide by the guidelines set forth below. However, with respect to (2), (3), (4), (5), (7) and (9) there is an exception in the partnership agreement for another program in which the interest of the managing general partner is substantially similar to or less than its interest in the partnerships. (1) Transfers at Cost. All leases will be acquired from the managing general partner and credited towards its required capital contribution at the cost of the lease, unless the managing general partner has a reason to believe that cost is materially more than the fair market value of the property. If the managing general partner believes cost is materially more than fair market value, then the managing general partner's credit for the contribution must be at a price not in excess of the fair market value. o A determination of fair market value must be supported by an appraisal from an independent expert and be maintained in the partnership's records for at least six years. (2) Equal Proportionate Interest. When the managing general partner sells or transfers an oil and gas interest to a partnership, it must, at the same time, sell or transfer to the partnership an equal proportionate interest in all its other property in the same prospect. 79 o The term "prospect" generally means an area which is believed to contain commercially productive quantities of natural gas or oil. However, a prospect will be limited to the drilling or spacing unit on which one well will be drilled if the following two conditions are met: o the well is being drilled to a geological feature which contains proved reserves as defined below; and o the drilling or spacing unit protects against drainage. The managing general partner believes that for a prospect located in Ohio, Pennsylvania and New York on which a well will be drilled to test the Clinton/ Medina geologic formation or the Mississippian and/or Upper Devonian Sandstone reservoirs, a prospect will consist of the drilling and spacing unit because it will meet the test in the preceding sentence. o Proved reserves, generally, are the estimated quantities of natural gas and oil which have been demonstrated to be recoverable in future years with reasonable certainty under existing economic and operating conditions. Proved reserves include proved undeveloped reserves which generally are reserves expected to be recovered from existing wells where a relatively major expenditure is required for recompletion or from new wells on undrilled acreage. Reserves on undrilled acreage will be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved Reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. The managing general partner anticipates that the majority of the wells drilled by each partnership will develop the Clinton/Medina geologic formation or the Mississippian and/or Upper Devonian Sandstone reservoirs. The drilling of these wells may provide the managing general partner with offset sites by allowing it to determine, at the partnership's expense, the value of adjacent acreage in which the partnership would not have any interest. The managing general partner owns acreage throughout the primary areas where each partnership's wells will be situated. To lessen this conflict of interest, for five years the managing general partner may not drill any well: o in the Clinton/Medina geologic formation within 1,650 feet of an existing partnership well in Pennsylvania or within 1,000 feet of an existing partnership well in Ohio; or o in the Mississippian/Upper Devonian Sandstone reservoirs in Fayette and Green Counties, Pennsylvania within 1,000 feet of an existing partnership well. If a partnership abandons its interest in a well, then this restriction will continue for one year following the abandonment. (3) Subsequently Enlarging Prospect. In areas where the prospect is not limited to the drilling or spacing unit and the area constituting a partnership's prospect is subsequently enlarged based on geological information, which is later acquired, then there is the following special provision: o if the prospect is enlarged to cover any area where the managing general partner owns a separate property interest and the partnership activities were material in establishing the existence of proved undeveloped reserves which are attributable to the separate property interest, then the 80 separate property interest or a portion thereof must be sold to the partnership in accordance with (1), (2) and (4). (4) Transfer of Less than the Managing General Partner's and its Affiliates' Entire Interest. If the managing general partner sells or transfers to a partnership less than all of its ownership in any prospect, then it must comply with the following conditions: o the retained interest must be a proportionate working interest; o the managing general partner's obligations and the partnership's obligations must be substantially the same after the sale of the interest by the managing general partner or its affiliates; and o the managing general partner's revenue interest must not exceed the amount proportionate to its retained working interest. For example, if the managing general partner transfers 50% of its working interest in a prospect to a partnership and retains a 50% working interest, then the partnership will not pay any of the costs associated with the managing general partner's retained working interest as a part of the transfer. This limitation does not prevent the managing general partner and its affiliates from subsequently dealing with their retained working interest as they may choose with unaffiliated parties or affiliated partnerships. For example, the managing general partner may sell its retained working interest to a third-party for a profit. (5) Limitations on Activities of the Managing General Partner and its Affiliates on Leases Acquired by a Partnership. For a five year period after the final closing of a partnership, if the managing general partner proposes to acquire an interest from an unaffiliated person in a prospect in which the partnership owns an interest or in a prospect in which the partnership's interest has been terminated without compensation within one year before the proposed acquisition, then the following conditions apply: o if the managing general partner does not currently own property in the prospect separately from the partnership, then the managing general partner may not buy an interest in the prospect; and o if the managing general partner currently owns a proportionate interest in the prospect separately from the partnership, then the interest to be acquired must be divided in the same proportion between the managing general partner and the partnership as the other property in the prospect. However, if the partnership does not have the cash or financing to buy the additional interest, then the managing general partner is also prohibited from buying the additional interest. (6) Limitations on Sale of Undeveloped and Developed Leases to the Managing General Partner. The managing general partner and its affiliates, other than an affiliated partnership, may not purchase undeveloped leases or receive a farmout from a partnership other than at the higher of cost or fair market value. Farmouts to the managing general partner and its affiliates also must be made as set forth in (9) below. The managing general partner and its affiliates, other than an affiliated income program, may not purchase any producing natural gas or oil property from a partnership unless: o the sale is in connection with the liquidation of the partnership; or o the managing general partner's well supervision fees under the drilling and operating agreement for the well have exceeded the net revenues of the well, determined without regard to the managing general partner's well supervision fees for the well, for a period of at least three consecutive months. 81 In both cases, the sale must be at fair market value supported by an appraisal of an independent expert selected by the managing general partner. The appraisal of the property must be maintained in the partnership's records for at least six years. (7) Transfer of Leases Between Affiliated Limited Partnerships. The transfer of an undeveloped lease from a partnership to an affiliated drilling limited partnership must be made as follows: o at fair market value if the undeveloped lease has been held for more than two years; or o at cost if the managing general partner deems it to be in the best interest of the partnership. An affiliated income program may purchase a producing natural gas and oil property from a partnership at any time at: o fair market value as supported by an appraisal from an independent expert if the property has been held by the partnership for more than six months or there have been significant expenditures made in connection with the property; or o cost as adjusted for intervening operations if the managing general partner deems it to be in the best interest of the partnership. However, these prohibitions do not apply to joint ventures or farmouts among affiliated partnerships, provided that: o the respective obligations and revenue sharing of all parties to the transaction are substantially the same; and o the compensation arrangement or any other interest or right of either the managing general partner or its affiliates is the same in each affiliated partnership or if different, the aggregate compensation of the managing general partner or the affiliate is reduced to reflect the lower compensation arrangement. (8) Leases Will Be Acquired Only for Stated Purpose of the Partnership. Each partnership must acquire only leases that are reasonably expected to meet the stated purposes of the partnership. Also, no leases may be acquired for the purpose of a subsequent sale, farmout or other disposition unless the acquisition is made after a well has been drilled to a depth sufficient to indicate that the acquisition would be in the partnership's best interest. (9) Farmout. The managing general partner will not enter into a farmout to avoid its paying its share of the costs related to drilling an undeveloped lease. However, the managing general partner's decision with respect to making a farmout and the terms of a farmout from a partnership involve conflicts of interest since the managing general partner may benefit from cost savings and reduction of risk. The partnership may farmout an undeveloped lease or well activity to the managing general partner, its affiliates or an unaffiliated third--party only if the managing general partner, exercising the standard of a prudent operator, determines that: o the partnership lacks the funds to complete the oil and gas operations on the lease or well and cannot obtain suitable financing; o drilling on the lease or the intended well activity would concentrate excessive funds in one location, creating undue risks to the partnership; 82 o the leases or well activity have been downgraded by events occurring after assignment to the partnership so that development of the leases or well activity would not be desirable; or o the best interests of the partnership would be served. If the partnership farmouts a lease or well activity, the managing general partner must retain on behalf of the partnership the economic interests and concessions as a reasonably prudent oil and gas operator would or could retain under the circumstances prevailing at the time, consistent with industry practices. However, if the farmout is made to the managing general partner or its affiliates there is a conflict of interest since the managing general partner will represent both the partnership and itself or an affiliate. Conflicts Between Investors and the Managing General Partner as an Investor The managing general partner, its officers, directors, and affiliates may subscribe for units in each partnership and the price of their units will be reduced by 10.5%, which is equal to the dealer-manager fee, the sales commission, the accountable marketing expense fee and the reimbursement of accountable due diligence expenses, which will not be paid with respect to these sales. Even though they pay a reduced price for their units these investors generally will: o share in the partnership's costs, revenues, and distributions on the same basis as the other investors as described in "Participation in Costs and Revenues"; and o have the same voting rights, except as discussed below. Any subscription by the managing general partner, its officers, directors, or affiliates will dilute the voting rights of you and the other investors and there may be a conflict with respect to certain matters. The managing general partner and its officers, directors and affiliates, however, are prohibited from voting with respect to certain matters as described in "Summary of Partnership Agreement - Voting Rights." Lack of Independent Underwriter and Due Diligence Investigation The terms of this offering, the partnership agreement, and the drilling and operating agreement were determined by the managing general partner without arms' length negotiations. You and the other investors have not been separately represented by legal counsel, who might have negotiated more favorable terms for you and the other investors in the offering and the agreements. Also, there was not an extensive in-depth "due diligence" investigation of the existing and proposed business activities of the partnerships and the managing general partner that would be provided by independent underwriters. Although Anthem Securities, which is affiliated with the managing general partner, serves as dealer-manager and will receive reimbursement of accountable due diligence expenses for certain due diligence investigations conducted by the selling agents which will be reallowed to the selling agents, its due diligence examination concerning this offering cannot be considered to be independent. Conflicts Concerning Legal Counsel The managing general partner anticipates that its legal counsel will also serve as legal counsel to each partnership and that this dual representation will continue in the future. If a future dispute arises between the managing general partner and you and the other investors in a partnership, then the managing general partner will cause you and the other investors to retain separate counsel. Also, if counsel advises the managing general partner that counsel reasonably believes its representation of a partnership will be adversely affected by its responsibilities to the managing general partner, then the managing general partner will cause you and the other investors in a partnership to retain separate counsel. 83 Conflicts Regarding Presentment Feature You and the other investors in a partnership have the right to present your units in the partnership to the managing general partner for purchase beginning with the fifth calendar year after the end of the calendar year in which your partnership closes. This creates the following conflicts of interest between you and the managing general partner. o The managing general partner may suspend the presentment feature if it does not have the necessary cash flow or it cannot borrow funds for this purpose on terms which it deems reasonable. Both of these determinations are subjective and will be made in the managing general partner's sole discretion. o The managing general partner will also determine the purchase price based on a reserve report that it prepares and is reviewed by an independent expert that it chooses. The formula for arriving at the purchase price has many subjective determinations that are within the discretion of the managing general partner. Conflicts Regarding Managing General Partner Withdrawing an Interest A conflict of interest is created with you and the other investors by the managing general partner's right to mortgage its interest or withdraw an interest in each partnership's wells equal to or less than its revenue interest to be used as collateral for a loan to the managing general partner. If there was a default under the loan, this could reduce the amount of the managing general partner's partnership net production revenues available for its subordination obligation to you and the other investors. Conflicts Regarding Order of Pipeline Construction and Gathering Fees The managing general partner may choose well locations along the Atlas Pipeline Partners gathering system which would benefit its parent company by providing more gathering fees to Atlas Pipeline Partners, even if there are other well locations available in the area or other areas which offer the partnerships a greater potential return. However, the managing general partner believes this conflict of interest is substantially reduced because the managing general partner expects to make the largest single capital contribution in each partnership as explained in "Capitalization and Source of Funds and Use of Proceeds." Thus, it is in the best interest of its parent company for the managing general partner to choose prospects for a partnership to drill which have the greatest potential reserves even if they are not connected to the Atlas Pipeline Partners gathering system. In addition, Atlas America or an affiliate will operate the gathering system for Atlas Pipeline Partners. Thus, the expansion of the Atlas Pipeline Partners gathering system will be within the control of the managing general partner's affiliate, which will attempt to expand the Atlas Pipeline Partners gathering system to those areas with the greatest number of wells with the greatest potential reserves. The managing general partner's affiliates are obligated through their agreement with Atlas Pipeline Partners to pay the difference between the amount each partnership pays for gathering fees to the managing general partner as set forth in "Compensation - Gathering Fees", and the greater of $.35 per mcf or 16% of the gross sales price for the natural gas. This provides an incentive to the managing general partner to increase the amount of the gathering fees paid by each partnership to it, which are not fixed and may change as described in "Compensation--Gathering Fees." However, the gathering fees paid to the managing general partner may not exceed competitive rates. Procedures to Reduce Conflicts of Interest In addition to the procedures set forth in " - Conflicts Involving the Acquisition of Leases", the managing general partner and its affiliates will comply with the following procedures in the partnership agreement to reduce some of the conflicts of interest with you and the other investors. The managing general partner does not have any other conflict of interest resolution procedures. Thus, conflicts of interest between the managing general partner and you and the other investors may not necessarily be resolved in your best interests. However, the managing general partner believes that its significant capital contribution to each partnership will reduce the conflicts of interest. (1) Fair and Reasonable. The managing general partner may not sell, transfer, or convey any property to, or purchase any property from, a partnership except: 84 o under transactions that are fair and reasonable; nor o take any action with respect to the assets or property of a partnership which does not primarily benefit the partnership. (2) No Compensating Balances. The managing general partner may not use a partnership's funds as a compensating balance for its own benefit. Thus, a partnership's funds may not be used to satisfy any deposit requirements imposed by a bank or other financial institution on the managing general partner for its own corporate purposes. (3) Future Production. The managing general partner may not commit the future production of a partnership well exclusively for its own benefit. (4) Disclosure. Any agreement or arrangement that binds a partnership must be fully disclosed in this prospectus. (5) No Loans from the Partnership. A partnership may not loan money to the managing general partner. (6) No Rebates. The managing general partner may not participate in any business arrangements which would circumvent these guidelines including receiving rebates or give-ups. (7) Sale of Assets. The sale of all or substantially all of the assets of a partnership may only be made with the consent of investors whose units equal a majority of the total units. (8) Participation in Other Partnerships. If a partnership participates in other partnerships or joint ventures, then the terms of the arrangements must not circumvent any of the requirements contained in the partnership agreement, including the following: o there may be no duplication or increase in organization and offering expenses, the managing general partner's compensation, partnership expenses, or other fees and costs; o there may be no substantive change in the fiduciary and contractual relationship between the managing general partner and you and the other investors; and o there may be no diminishment in your voting rights. (9) Investments. A partnership's funds may not be invested in the securities of another person except in the following instances: o investments in working interests made in the ordinary course of the partnership's business; o temporary investments in income producing short-term highly liquid investments, in which there is appropriate safety of principal, such as U.S. Treasury Bills; o multi-tier arrangements meeting the requirements of (8) above; o investments involving less than 5% of the total subscription proceeds of the partnership that are a necessary and incidental part of a property acquisition transaction; and o investments in entities established solely to limit the partnership's liabilities associated with the ownership or operation of property or equipment, provided that duplicative fees and expenses are prohibited. (10) Safekeeping of Funds. The managing general partner may not employ, or permit another to employ, the funds or assets of a partnership in any manner except for the exclusive benefit of the partnership. The managing general 85 partner has a fiduciary responsibility for the safekeeping and use of all funds and assets of each partnership whether or not in its possession or control. (11) Advance Payments. Advance payments by each partnership to the managing general partner and its affiliates are prohibited except when advance payments are required to secure the tax benefits of prepaid intangible drilling costs and for a business purpose. Policy Regarding Roll-Ups It is possible at some indeterminate time in the future that each partnership may become involved in a roll-up. In general, a roll-up means a transaction involving the acquisition, merger, conversion, or consolidation of a partnership with or into another partnership, corporation or other entity, and the issuance of securities by the roll-up entity to you and the other investors. A roll-up will also include any change in the rights, preferences, and privileges of you and the other investors in the partnership. These changes could include the following: o increasing the compensation of the managing general partner; o amending your voting rights; o listing the units on a national securities exchange or on NASDAQ; o changing the partnership's fundamental investment objectives; or o materially altering the partnership's duration. If a roll-up should occur in the future the partnership agreement provides various policies which include the following: o an independent expert must appraise all partnership assets, and you must receive a summary of the appraisal in connection with a proposed roll-up; o if you vote "no" on the roll-up proposal, then you will be offered a choice of: o accepting the securities of the roll-up entity; or o one of the following: o remaining a partner in the partnership and preserving your units in the partnership on the same terms and conditions as existed previously; or o receiving cash in an amount equal to your pro-rata share of the appraised value of the partnership's net assets; and o the partnership will not participate in a proposed roll-up: o unless approved by investors whose units equal 66% of the total units; o which would result in the diminishment of your voting rights under the roll-up entity's chartering agreement; o which includes provisions which would operate to materially impede or frustrate the accumulation of shares by you of the securities of the roll-up entity; 86 o in which your right of access to the records of the roll-up entity would be less than those provided by the partnership agreement; or o in which any of the transaction costs would be borne by the partnership if the proposed roll-up is not approved by investors whose units equal 66% of the total units. FIDUCIARY RESPONSIBILITY OF THE MANAGING GENERAL PARTNER In General The managing general partner will manage each partnership and its assets. In conducting your partnership's affairs the managing general partner is accountable to you as a fiduciary. Under Delaware law this generally means that the managing general partner must exercise due care and deal fairly with you and the other investors. Neither the partnership agreement nor any other agreement between the managing general partner and each partnership may contractually limit any fiduciary duty owed to you and the other investors by the managing general partner under applicable law except as set forth in Sections 4.01, 4.02, 4.04, 4.05, and 4.06 of the partnership agreement. For example, the partnership agreement does permit: o the managing general partner and its affiliates to have business interests or activities that may conflict with the partnerships if the managing general partner and its affiliates determine that the opportunity either: o cannot be pursued by the partnership because of insufficient funds; or o it is not appropriate for the partnership under the existing circumstances; o the managing general partner and its affiliates to be indemnified and held harmless as described below in "- Limitations on Managing General Partner Liability as Fiduciary"; o the managing general partner to devote only so much of its time as is necessary to manage the affairs of each partnership; o the managing general partner and its affiliates to conduct business with the partnerships in a capacity other than as managing general partner or sponsor as described in ss.ss.4.01, 4.02, 4.04, 4.05 and 4.06 of the partnership agreement; and o the managing general partner to manage multiple programs simultaneously. Other than as set forth above, the partnership agreement does not excuse the managing general partner from liability or provide it with any defense for breach of its fiduciary duty. The fiduciary duty owed by the managing general partner to the partnership is analogous to the fiduciary duty owed by directors to a corporation and its stockholders and is subject to the same rule, commonly referred to as the "business judgment rule," that directors are not liable for mistakes made in the good faith exercise of honest business judgment or for losses incurred in the good faith performance of their duties when performed with such care as an ordinarily prudent person would use. As a result of the business judgment rule, the managing general partner may not be held liable for mistakes made or losses incurred in the good faith exercise of reasonable business judgment as described below in " - Limitations on Managing General Partner Liability as Fiduciary." If the managing general partner breaches its fiduciary responsibilities, then you are entitled to an accounting and the recovery of any economic loss caused by the breach. The Delaware Revised Uniform Limited Partnership Act provides that a limited partner may institute legal action (a "derivative" action) on a partnership's behalf to recover damages from a third-party when the managing general partner refuses to institute the action or where an effort to cause the managing general partner to do so is not likely to succeed. In addition, the statutory or case law may permit a limited partner to institute legal action on behalf of himself and all other similarly situated limited partners (a "class action") to recover damages from the managing general 87 partner for violations of its fiduciary duties to the limited partners. This is a rapidly expanding and changing area of the law, and if you have questions concerning the managing general partner's duties you are urged to consult your own counsel. Limitations on Managing General Partner Liability as Fiduciary Under the terms of the partnership agreement the managing general partner, the operator, and their affiliates have limited their liability to each partnership and to you and the other investors for any loss suffered by your partnership or you and the other investors in the partnership which arises out of any action or inaction on their part if: o they determined in good faith that the course of conduct was in the best interest of the partnership; o they were acting on behalf of, or performing services for, the partnership; and o their course of conduct did not constitute negligence or misconduct. In addition, the partnership agreement provides for indemnification of the managing general partner, the operator, and their affiliates by each partnership against any losses, judgments, liabilities, expenses, and amounts paid in settlement of any claims sustained by them in connection with that partnership provided that they meet the standards set forth above. However, there is a more restrictive standard for indemnification for losses arising from or out of an alleged violation of federal or state securities laws. Also, to the extent that any indemnification provision in the partnership agreement purports to include indemnification for liabilities arising under the Securities Act of 1933, as amended, you should be aware that, in the SEC's opinion, this indemnification is contrary to public policy and therefore unenforceable. Payments arising from the indemnification or agreement to hold harmless are recoverable only out of a partnership's: o tangible net assets; o revenues; and o insurance proceeds. Still, use of partnership funds or assets for indemnification of the managing general partner, the operator, or an affiliate would reduce amounts available for partnership operations or for distribution to you and the other investors. A partnership may not pay the cost of the portion of any insurance that insures the managing general partner, the operator, or an affiliate against any liability for which they cannot be indemnified. However, a partnership's funds can be advanced to them for legal expenses and other costs incurred in any legal action for which indemnification is being sought if the partnership has adequate funds available and certain conditions in the partnership agreement are met. The effect of the foregoing provisions and the business judgment rule may be to limit your recourse to the managing general partner. MATERIAL FEDERAL INCOME TAX CONSEQUENCES Summary of Tax Opinion The managing general partner has received the tax opinion of special counsel, Kunzman & Bollinger, Inc., Oklahoma City, Oklahoma, which is included as Exhibit 8 to the registration statement. This section of the prospectus is a summary of the tax opinion and all the material federal income tax consequences of the purchase, ownership and disposition of the investor general partner and limited partner units. Different tax considerations than those addressed in this discussion may apply to foreign persons, corporations, partnerships, trusts and other prospective investors which are not treated as typical investors in the partnerships for federal income tax 88 purposes. In this regard, the managing general partner has represented that "typical investors" are natural persons who purchase units in this offering and are U.S. citizens. Also, the treatment of the tax attributes of a partnership may vary among investors. Accordingly, you are urged to read the entire tax opinion and seek qualified, professional assistance in the preparation of your federal, state and local tax returns with specific reference to your own tax situation. (See "Additional Information.") The tax opinion represents only special counsel's best legal judgment, and has no binding effect or official status. It is only special counsel's prediction as to the outcome of the issues addressed and the results are not certain. There is no assurance that the present laws or regulations will not be changed and adversely affect you. Also, the IRS may challenge the deductions claimed by a partnership or you, or the taxable year in which the deductions are claimed, and no guaranty can be given that the challenge would not be upheld if litigated. No advance ruling on any tax consequence of an investment in a partnership will be requested from the IRS. Also, special counsel's opinions are based in part on certain factual assumptions which are set forth in the tax opinion and certain factual representations of the managing general partner which special counsel has assumed for purposes of its opinions. In special counsel's opinion the following tax treatment will be upheld if challenged by the IRS and litigated. o Partnership Classification. Each partnership will be classified as a partnership for federal income tax purposes, and not as a corporation. The partnerships, as such, will not pay any federal income taxes, and all items of income, gain, loss, and deduction of the partnerships will be reportable by the partners in the partnership in which they invest. o Passive Activity Classification. o Generally, the passive activity limitations on losses under ss.469 of the Internal Revenue Code will apply to limited partners, but will not apply to investor general partners before the conversion of investor general partner units to limited partner units. o Each partnership's income and gain from its natural gas and oil properties which are allocated to its limited partners, other than net income and gain in the case of converted investor general partners, generally will be characterized as passive activity income which may be offset by passive activity losses. o Income or gain attributable to investments of working capital of each partnership will be characterized as portfolio income, which cannot be offset by passive activity losses. o Not a Publicly Traded Partnership. None of the partnerships will be treated as a publicly traded partnership under the Internal Revenue Code. o Availability of Certain Deductions. Business expenses, including payments for personal services actually rendered in the taxable year in which accrued, which are reasonable, ordinary and necessary and do not include amounts for items such as lease acquisition costs, organization and syndication fees and other items which are required to be capitalized, are currently deductible. o Intangible Drilling Costs. Each partnership will elect to deduct currently all intangible drilling costs. However, an investor in a partnership may elect instead to capitalize and deduct all or part of his share of the intangible drilling costs ratably over a 60 month period as discussed in "- Minimum Tax - Tax Preferences," below. Subject to the foregoing, intangible drilling costs paid by a partnership under the terms of bona fide drilling contracts for the partnership's wells will be deductible in the taxable year in which the payments are made and the drilling services are rendered, assuming the amounts are reasonable 89 consideration based on the managing general partner's representations, and subject to certain restrictions summarized below, including basis and "at risk" limitations, and the passive activity loss limitation with respect to the limited partners. o Prepayments of Intangible Drilling Costs. Depending primarily on when each partnership's subscriptions are received, the managing general partner anticipates that Atlas America Public #12-2003 Limited Partnership will prepay in 2003 most, if not all, of its intangible drilling costs for drilling activities that will begin in 2004. In addition, the managing general partner anticipates that Atlas America Public #12-2004(B) Limited Partnership, which may close on December 31, 2004, may prepay in 2004 most, if not all, of its intangible drilling costs for drilling activities that will begin in 2005. Assuming that the amounts of any prepaid intangible drilling costs of a partnership are reasonable consideration based on the managing general partner's representations, and based in part on the factual assumptions set forth below, the prepayments of intangible drilling costs will be deductible in the year in which they are made even though all working interest owners in the well may not be required to prepay intangible drilling costs, subject to certain restrictions summarized below, including basis and "at risk" limitations, and the passive activity loss limitation with respect to the limited partners. The foregoing opinion is based in part on the assumptions that: o the intangible drilling costs will be required to be prepaid in the year in which they are made for specified wells under the drilling and operating agreement; o under the drilling and operating agreement the drilling of all of the wells is required to be, and actually is, begun before the close of the 90th day after the close of the taxable year in which the prepayment is made, and the wells are continuously drilled until completed, if warranted, or abandoned; and o the required prepayments are not refundable to the partnership which made the prepayment and any excess prepayments are applied to intangible drilling costs of substitute wells. o Depletion Allowance. The greater of cost depletion or percentage depletion will be available to qualified investors as a current deduction against their share of the natural gas and oil production income of the partnership in which they invest, subject to certain restrictions summarized below. o MACRS. Each partnership's reasonable costs for equipment placed in the wells which cannot be deducted immediately ("Tangible Costs") will be eligible for cost recovery deductions under the Modified Accelerated Cost Recovery System ("MACRS"), generally over a seven year "cost recovery period," subject to certain restrictions summarized below, including basis and "at risk" limitations and the passive activity loss limitation in the case of the limited partners. Subject to the foregoing, each partnership will be entitled to an additional first-year depreciation allowance based on 50% of the adjusted basis of its "qualified" tangible costs for productive wells which are completed and made capable of production, i.e. placed in service, before January 1, 2005. This additional first-year depreciation allowance will reduce the partnership's remaining regular MACRS depreciation allowances beginning with the year in which the wells are placed in service. However, none of the MACRS depreciation deductions for a partnership's "qualified" tangible costs will increase the alternative minimum taxable income of that partnership's investors. o Tax Basis of Units. Each investor's adjusted tax basis in his units will be increased by his total subscription proceeds. 90 o At Risk Limitation on Losses. Each investor initially will be "at risk" to the full extent of his subscription proceeds, assuming that: o each investor has an objective to carry on the business of the partnership in which he invests for profit; o any amount borrowed by an investor and contributed to a partnership will not be borrowed from a person who has an interest in the partnership, other than as a creditor, or a "related person", as that term is defined in ss.465 of the Internal Revenue Code, to a person, other than the investor, having an interest in the partnership, other than as a creditor, and the investor will be severally, primarily, and personally liable for the borrowed amount; and o no investor will have protected himself from loss for amounts contributed to the partnership in which he invests through nonrecourse financing, guarantees, stop loss agreements or other similar arrangements. o Allocations. Assuming the effect of the allocations of income, gain, loss and deduction, or items thereof, set forth in the partnership agreement, including the allocations of basis and amount realized with respect to natural gas and oil properties, is substantial in light of an investor's tax attributes that are unrelated to the partnership in which he invests, the allocations will have "substantial economic effect" and will govern each investor's distributive share of those items to the extent the allocations do not cause or increase deficit balances in the investors' capital accounts. o Subscription. No gain or loss will be recognized by the investors on payment of their subscriptions. o Profit Motive. Assuming that each investor has an objective to carry on the business of the partnership in which he invests for profit, the partnerships will possess the requisite profit motive under ss.183 of the Internal Revenue Code. This opinion is based in part on the results of the previous partnerships sponsored by the managing general partner set forth in "Prior Activities" and the managing general partner's representations that each partnership will be operated as described in the prospectus and the principal purpose of each partnership is to locate, produce and market natural gas and oil on a profitable basis apart from tax benefits (which is supported by the geological evaluations and other information for the proposed prospects for Atlas America Public #12-2003 Limited Partnership included in Appendix A to the prospectus). o No Tax Shelter Registration. None of the partnerships is required to register with the IRS as a tax shelter. This opinion is based in part on the managing general partner's representations that none of the partnerships has a tax shelter ratio greater than 2 to 1 and each partnership will be operated as described in the prospectus. o Anti-Abuse Rules and Judicial Doctrines. Assuming that each investor has an objective to carry on the business of the partnership in which he invests for profit, potentially relevant statutory or regulatory anti-abuse rules and judicial doctrines will not have a material adverse effect on the tax consequences of an investment in a partnership by a typical investor as described in special counsel's opinions. This opinion is based in part on the results of the previous partnerships sponsored by the managing general partner set forth in "Prior Activities" in the prospectus and the managing general partner's representations that each partnership will be operated as described in the prospectus and the principal purpose of each partnership is to locate, produce and market natural gas and oil on a profitable basis apart from tax benefits (which is supported by the geological evaluations and other information for the proposed prospects for Atlas America Public #12-2003 Limited Partnership included in Appendix A to the prospectus). 91 o Overall Evaluation of Tax Benefits. The tax benefits of each partnership, in the aggregate, which are a significant feature of an investment in a partnership by a typical investor will be realized as contemplated by the prospectus. This opinion is based on special counsel's conclusion that substantially more than half of the material tax benefits of each partnership, in terms of their financial impact on a typical investor, will be realized if challenged by the IRS. * * * * * * * * * * * * * In General The following is a summary of all of the material federal income tax consequences of the purchase, ownership and disposition of investor general partner units and limited partner units discussed in the tax opinion which will apply to typical investors in a partnership. Partnership Classification For federal income tax purposes a partnership is not a taxable entity. The partners, rather than the partnership, receive any deductions, as well as the income, from the operations engaged in by the partnership. A business entity with two or more members is classified for federal tax purposes as either a corporation or a partnership. Each partnership will be formed as a limited partnership under the Delaware Revised Uniform Limited Partnership Act which describes each partnership as a "partnership," Thus, each partnership automatically will be classified as a partnership unless it elects to be classified as a corporation. In this regard, the managing general partner has represented that none of the partnerships will elect to be taxed as a corporation. Limitations on Passive Activities Under the passive activity rules of the Internal Revenue Code, all income of a taxpayer who is subject to the rules is categorized as: o income from passive activities such as limited partners' interests in a business; o active income such as salary, bonuses, etc.; or o portfolio income such as gain, interest, dividends and royalties unless earned in the ordinary course of a trade or business. Losses generated by passive activities can offset only passive income and cannot be applied against active income or portfolio income. Suspended losses may be carried forward indefinitely, but not back, and used to offset future years' passive activity income. Passive activities include any trade or business in which the taxpayer does not materially participate on a regular, continuous, and substantial basis. Under the partnership agreement limited partners will not have material participation in the partnership in which they invest and generally will be subject to the passive activity limitations. Investor general partners also do not materially participate in the partnership in which they invest. However, because each partnership will own only "working interests," as defined in the Internal Revenue Code, in its wells and investor general partners will not have limited liability under Delaware law until they are converted to limited partners, their deductions generally will not be treated as passive deductions before the conversion. However, if an investor general partner invests in a partnership through an entity which limits his liability, for example, a limited partnership in which he is a limited partner, a limited liability company or an S corporation, then he generally will be subject to the passive activity limitations the same as a limited partner. Contractual limitations on the liability of investor general partners under the partnership agreement such as insurance, limited indemnification, etc. will not cause investor general partners to be subject to the passive activity limitations. 92 Publicly Traded Partnership Rules. Net losses of a partner from each publicly traded partnership are suspended and carried forward to be netted against income from that publicly traded partnership only. In addition, net losses from other passive activities may not be used to offset net passive income from a publicly traded partnership. However, in the opinion of special counsel none of the partnerships will be treated as a publicly traded partnership under the Internal Revenue Code. Conversion from Investor General Partner to Limited Partner. If you invest in a partnership as an investor general partner, then your share of the partnership's deduction for intangible drilling costs in the year in which you invest will not be subject to the passive activity limitations because your investor general partner units will not be converted to limited partner units until after all of the partnership's wells have been drilled and completed. (See "Actions to be Taken by Managing General Partner to Reduce Risks of Additional Payments by Investor General Partners" and "- Drilling Contracts," below.) After the investor general partner units have been converted to limited partner units, each former investor general partner will have limited liability as a limited partner under the Delaware Revised Uniform Limited Partnership Act with respect to his partnership's activities after the date of the conversion. Concurrently, the investor general partner will become subject to the passive activity limitations as a limited partner. However, the former investor general partner previously will have received a non-passive loss as an investor general partner in the year in which he invested in the partnership as a result of the partnership's deduction for intangible drilling costs. Therefore, the Internal Revenue Code requires that his net income from the partnership's wells after his conversion to a limited partner must continue to be characterized as non-passive income which cannot be offset with passive losses. An investor general partner's conversion of his investor general partner units into limited partner units should not have any other adverse tax consequences unless the investor general partner's share of any partnership liabilities is reduced as a result of the conversion. A reduction in a partner's share of liabilities is treated as a constructive distribution of cash to the partner, which reduces the basis of the partner's interest in the partnership and is taxable to the extent it exceeds his basis. Taxable Year and Method of Accounting Each partnership intends to adopt a calendar year taxable year and will use the accrual method of accounting for federal income tax purposes. 2003 and 2004 Expenditures The managing general partner anticipates that all of your partnership's subscription proceeds will be expended in the year in which you invest in the partnership and that your share of the partnership's income and deductions, including the deduction for intangible drilling costs, will be reflected on your federal income tax return for that period. Depending primarily on when each partnership's subscription proceeds are received, the managing general partner anticipates that Atlas America Public #12-2003 Limited Partnership will prepay in 2003 most, if not all, of its intangible drilling costs for drilling activities that will begin in 2004. In addition, the managing general partner anticipates that Atlas America Public #12-2004(B) Limited Partnership, which may close on December 31, 2004, may prepay in 2004 most, if not all, of its intangible drilling costs for drilling activities that will begin in 2005. The deductibility of these advance payments in the year in which you invest in the partnership cannot be guaranteed. (See "- Drilling Contracts," below.) In addition, wells which are prepaid in 2004 and drilled and completed in 2005, if any, will not be eligible for the additional 50% first-year depreciation deduction discussed in "- Depreciation - Modified Accelerated Cost Recovery System ("MACRS"), below. Availability of Certain Deductions Ordinary and necessary business expenses, including reasonable compensation for personal services actually rendered, are deductible in the year incurred. The managing general partner has represented that the amounts payable to the managing general partner and its affiliates, including the amounts payable to the managing general partner or its affiliates as general drilling contractor, are reasonable amounts which would ordinarily be paid for similar services in similar transactions. The fees paid to the managing general partner and its affiliates will not be currently deductible if they are: o in excess of reasonable compensation; 93 o properly characterized as organization or syndication fees or other capital costs such as the acquisition cost of the leases; or o not "ordinary and necessary" business expenses. In the event of an audit, payments to the managing general partner and its affiliates by a partnership will be scrutinized by the IRS to a greater extent than payments to an unrelated party. Intangible Drilling Costs Subject to the passive activity loss rules in the case of limited partners, you will be entitled to deduct your share of your partnership's intangible drilling costs, which include items which do not have salvage value, such as labor, fuel, repairs, supplies and hauling necessary to the drilling of a well. Intangible drilling costs generally will be treated as ordinary income if a property or your units are sold at a gain. Also, productive-well intangible drilling costs may subject you to an alternative minimum tax in excess of regular tax unless you elect to deduct all or part of these costs ratably over a 60-month period as discussed in "- Minimum Tax - Tax Preferences," below. The managing general partner estimates that on average approximately 78% of the total price to be paid by each partnership for all of its completed wells will be intangible drilling costs which are charged under the partnership agreement 100% to you and the other investors in the partnership. Also, under the partnership agreement not less than 90% of the subscription proceeds received by your partnership from you and the other investors will be used to pay intangible drilling costs. The IRS could challenge the characterization of a portion of these costs as deductible intangible drilling costs and recharacterize the costs as some other item which may be nondeductible. However, this would have no effect on the allocation and payment of the costs by you and the other investors under the partnership agreement. You are urged to consult with your personal tax advisor concerning the tax benefits to you of the deduction for intangible drilling costs in the partnership in which you invest in light of your own tax situation. Drilling Contracts Each partnership will enter into the drilling and operating agreement with the managing general partner or its affiliates, as a third-party general drilling contractor, to drill and complete the partnership's development wells on a cost plus 15% basis. For its services as general drilling contractor, the managing general partner anticipates that on average over all of the wells drilled and completed by each partnership, assuming a 100% working interest in each well, it will have reimbursement of general and administrative overhead of $14,142 per well and a profit of 15% (approximately $26,083) per well with respect to the intangible drilling costs and the portion of equipment costs paid by you and the other investors in your partnership as described in "Compensation - Drilling Contracts". However, the actual cost of drilling and completing the wells may be more or less than the estimated amount, due primarily to the uncertain nature of drilling operations, and the managing general partner's profit per well also could be more or less than the dollar amount estimated by the managing general partner. The managing general partner believes the prices under the drilling and operating agreement are competitive in the proposed areas of operation. Nevertheless, the amount of the profit realized by the managing general partner under the drilling and operating agreement could be challenged by the IRS as unreasonable and disallowed as a deductible intangible drilling cost. Depending primarily on when each partnership's subscription proceeds are received, the managing general partner anticipates that Atlas America Public #12-2003 Limited Partnership will prepay in 2003 most, if not all, of its intangible drilling costs for drilling activities that will begin in 2004. In addition, the managing general partner anticipates that Atlas America Public #12-2004(B) Limited Partnership, which may close on December 31, 2004, may prepay in 2004 most, if not all, of its intangible drilling costs for drilling activities that will begin in 2005. In Keller v. Commissioner, 79 T.C. 7 (1982), aff'd 725 F.2d 1173 (8th Cir. 1984), the Tax Court applied a two-part test for the current deductibility of prepaid intangible drilling costs. The test is: 94 o the expenditure must be a payment rather than a refundable deposit; and o the deduction must not result in a material distortion of income taking into substantial consideration the business purpose aspects of the transaction. Each partnership will attempt to comply with the guidelines set forth in Keller with respect to any prepaid intangible drilling costs. The drilling and operating agreement will require each partnership to prepay intangible drilling costs in the year in which you invest for specified wells the drilling of which may begin in the following year. Prepayments should not result in a loss of current deductibility where: o there is a legitimate business purpose for the required prepayment; o the contract is not merely a sham to control the timing of the deduction; and o there is an enforceable contract of economic substance. The drilling and operating agreement will require each partnership to prepay the intangible drilling costs of drilling and completing its wells in order to enable the operator to: o begin site preparation for the wells; o obtain suitable subcontractors at the then current prices; and o insure the availability of equipment and materials. Under the drilling and operating agreement excess prepaid amounts, if any, will not be refundable to the partnership but will be applied to intangible drilling costs to be incurred in drilling and completing substitute wells. Under Keller, a provision for substitute wells should not result in the prepayments being characterized as refundable deposits. The likelihood that prepayments will be challenged by the IRS on the grounds that there is no business purpose for the prepayment is increased if prepayments are not required with respect to all of the working interest in the well. It is possible that less than 100% of the working interest will be acquired by a partnership in one or more wells and prepayments may not be required of all owners of working interests in the wells. However, in the view of special counsel, a legitimate business purpose for the required prepayments may exist under the guidelines set forth in Keller, even though prepayment is not required by the drilling contractor with respect to a portion of the working interest in the wells. In addition, a current deduction for prepaid intangible drilling costs is available only if the drilling of the wells begins before the close of the 90th day after the close of the taxable year in which the prepayment was made. Under the drilling and operating agreement, the managing general partner as operator and general drilling contractor will use its best efforts to begin drilling the wells no later than March 30, 2004 for Atlas America Public #12-2003 Limited Partnership and March 31, 2005 for Atlas America Public #12-2004(B) Limited Partnership. However, the drilling of any partnership well may be delayed due to circumstances beyond the control of the managing general partner or the drilling subcontractors. These circumstances include, for example: o the unavailability of drilling rigs; o decisions of third-party operators to delay drilling the wells; o poor weather conditions; 95 o inability to obtain drilling permits or access right to the drilling site; or o title problems. Due to the foregoing factors, no guaranty is made by the managing general partner under the drilling and operating agreement that the drilling of all wells prepaid by a partnership will actually begin by the deadline set by the Internal Revenue Code for the partnership in which you invest. If the drilling of a prepaid partnership well does not begin by that date, deductions claimed by you for prepaid intangible drilling costs for the well in the year in which you invest in the partnership would be disallowed and deferred to the next taxable year when the well is actually drilled. No assurance can be given that on audit the IRS would not disallow the current deductibility of a portion or all of any prepayments of intangible drilling costs under a partnership's drilling contracts, thereby decreasing the amount of deductions allocable to the investors in that partnership for the year in which they invest, or that the challenge would not ultimately be sustained. In the event of disallowance, the deduction for prepaid intangible drilling costs would be available in the next year when the wells are actually drilled. Depletion Allowance Proceeds from the sale of each partnership's natural gas and oil production will constitute ordinary income. A certain portion of the income will not be taxable under the depletion allowance which permits the deduction from gross income for federal income tax purposes of either the percentage depletion allowance or the cost depletion allowance, whichever is greater. Depletion deductions generally will be treated as ordinary income if a property or your units are sold at a gain. Cost depletion for any year is determined by dividing the adjusted tax basis for the property by the total units of natural gas or oil expected to be recoverable from the property and then multiplying the resultant quotient by the number of units actually sold during the year. Cost depletion cannot exceed the adjusted tax basis of the property to which it relates. Percentage depletion generally is available to taxpayers other than "integrated oil companies," which term does not include the partnerships. Percentage depletion is based on your share of your partnership's gross production income from its natural gas and oil properties. The rate of percentage depletion is 15%. However, percentage depletion for marginal production increases 1%, up to a maximum increase of 10%, for each whole dollar that the domestic wellhead price of crude oil for the immediately preceding year is less than $20 per barrel without adjustment for inflation. The term "marginal production" includes natural gas and oil produced from a domestic stripper well property, which is defined as any property which produces a daily average of 15 or less equivalent barrels of oil, which is equivalent to 90 mcf of natural gas, per producing well on the property in the calendar year. Most, if not all, of each partnership's wells will qualify for these potentially higher rates of percentage depletion. The rate of percentage depletion for marginal production in 2003 is 15%. This rate may fluctuate from year to year depending on the price of oil, but will not be less than the statutory rate of 15% nor more than 25%. Also, percentage depletion: o may not exceed 100% of the net income from each natural gas and oil property before the deduction for depletion; and o is limited to 65% of the taxpayer's taxable income for a year computed without regard to deductions for percentage depletion, net operating loss carry-backs and capital loss carry-backs. Availability of percentage depletion must be computed separately by you, and not by your partnership or for investors in your partnership as a whole. You are urged to consult your own tax advisors with respect to the availability of percentage depletion to you. 96 Depreciation - Modified Accelerated Cost Recovery System ("MACRS") Equipment costs ("Tangible Costs") and the related depreciation deductions of each partnership generally are charged and allocated under the partnership agreement 66% to the managing general partner and 34% to you and the other investors in the partnership. However, if the total equipment costs for all of the partnership's wells that would be charged to you and the other investors exceeds an amount equal to 10% of the subscription proceeds of you and the other investors, then the excess, together with the related depreciation deductions, will be charged and allocated to the managing general partner. These deductions are subject to recapture as ordinary income rather than capital gain on the disposition of the property or your units. The cost of most equipment placed in service by each partnership will be recovered through depreciation deductions over a seven year cost recovery period, using the 200% declining balance method, with a switch to straight-line to maximize the deduction. In the case of a short tax year the MACRS deduction is prorated on a 12-month basis. No distinction is made between new and used property and salvage value is disregarded. Except as discussed below, generally only a half-year of depreciation is allowed for the year recovery property is placed in service or disposed of, and smaller depreciation deductions are used for purposes of the alternative minimum tax. Notwithstanding the foregoing, under the Jobs and Growth Tax Relief Reconciliation Act of 2003 ("2003 Tax Act"), for federal income tax purposes each partnership will be entitled to an additional first-year depreciation allowance based on 50% of the adjusted basis of its "qualified" equipment costs. For this purpose, a partnership's "qualified" equipment costs means the partnership's equipment costs for productive wells which are completed and made capable of production, i.e. placed in service, before January 1, 2005. Thus, with respect to Atlas America Public #12-2004(B) Limited Partnership, which may close on December 31, 2004, this additional first-year depreciation allowance would not be available for wells, if any, which are prepaid by the partnership and drilled and completed after January 1, 2005. The basis of this qualified equipment will be reduced by the additional 50% first-year depreciation allowance for purposes of calculating the regular MACRS depreciation allowances beginning with the year the wells are placed in service. The examples provided in the Technical Explanation of the Job Creation and Worker Assistance Act of 2002 ("2002 Tax Act") which provided a similar accelerated depreciation allowance of 30%, do not reduce the 30% additional depreciation allowance by the half-year convention discussed above. Nevertheless, because this situation is not clearly addressed by either the 2002 Tax Act or the 2003 Tax Act, it is possible that the half-year convention or a mid-quarter convention, depending on when a partnership's wells are placed in service, ultimately may be determined to apply under the 2003 Tax Act. o Also, you will not incur any alternative minimum tax adjustment with respect to your share of a partnership's additional 50% first-year depreciation allowance, nor any of its other depreciation deductions for the costs of the qualified equipment it places in the wells. Lease Acquisition Costs and Abandonment Lease acquisition costs, together with the related cost depletion deduction and any abandonment loss for lease costs, are allocated under the partnership agreement 100% to the managing general partner, which will contribute the leases to each partnership as a part of its capital contribution. Tax Basis of Units Your share of your partnership's losses is allowable only to the extent of the adjusted basis of your units at the end of the partnership's taxable year. The adjusted basis of your units will be adjusted, but not below zero, for any gain or loss to you from a disposition by the partnership of a natural gas or oil property, and will be increased by your: o cash subscription payment; o share of partnership income; and o share, if any, of partnership debt. The adjusted basis of your units will be reduced by your: 97 o share of partnership losses; o depletion deductions, but not below zero; and o cash distributions from the partnership. The reduction in your share of partnership liabilities, if any, is considered a cash distribution to you. Should cash distributions to you from your partnership exceed the tax basis of your units, taxable gain would result to the extent of the excess. "At Risk" Limitation for Losses Subject to the limitations on "passive losses" generated by each partnership in the case of limited partners, and your basis in your units, you may use your share of your partnership's losses to offset income from other sources. However, you may deduct the loss only to the extent of the amount you have "at risk" in the partnership at the end of a taxable year. Your initial amount "at risk" is limited to the amount of money you paid for your units in the partnership. However, the amount you have "at risk" may not include the amount of any loss that you are protected against through: o nonrecourse loans; o guarantees; o stop loss agreements; or o other similar arrangements. Distributions from a Partnership Generally, a cash distribution from your partnership to you in excess of the adjusted basis of your units immediately before the distribution is treated as gain from the sale or exchange of your units to the extent of the excess. No loss can be recognized by you on these distributions. Also, other distributions of property and liquidating distributions of your partnership may result in taxable gain or loss to you. Sale of the Properties Under the Jobs and Growth Tax Relief Reconciliation Act of 2003 ("2003 Tax Act"), the maximum tax rates on a noncorporate taxpayer's adjusted net capital gain on the sale of assets held more than a year of 20%, or 10% to the extent it would have been taxed at a 10% or 15% rate if it had been ordinary income, have been reduced to 15% and 5%, respectively, for most capital assets sold or exchanged after May 5, 2003. In addition, for 2008 only, the 5% tax rate on adjusted net capital gain is reduced to 0%. The 2003 Tax Act also eliminated the former maximum tax rates of 18% and 8%, respectively, on qualified five-year gain. The new capital gain rates also apply for purposes of the alternative minimum tax. However, the former tax rates are scheduled to be reinstated January 1, 2009, as if the 2003 Tax Act had never been enacted. "Adjusted net capital gain" means net capital gain, less certain types of net capital gain that are taxed a maximum rate of 28% (such as gain on the sale of most collectibles and gain on the sale of certain small business stock); or 25% (gain attributable to real estate depreciation). "Net capital gain" means the excess of net long-term gain (excess of long-term gains over long-term losses) over net short-term loss (excess of short-term gains over short-term losses). The annual capital loss limitation for noncorporate taxpayers is the amount of capital gains plus the lesser of $3,000, which is reduced to $1,500 for married persons filing separate returns, or the excess of capital losses over capital gains. Gains and losses from sales of natural gas and oil properties held for more than 12 months generally will be treated as a long-term capital gain, while a net loss will be an ordinary deduction. However, on disposition of a natural gas or oil property gain is treated as ordinary income to the extent of the lesser of: 98 o the amounts that were deducted as intangible drilling costs rather than added to basis, plus depletion deductions that reduced the basis of the property, depreciation deductions and certain losses, if any, on previous sales of partnership assets; or o the amount realized in the case of a sale, exchange or involuntary conversion or fair market value in all other cases, minus the property's adjusted basis. Other gains and losses on sales of natural gas and oil properties will generally result in ordinary gains or losses. Disposition of Units The sale or exchange, including a purchase by the managing general partner, of all or part of your units held by you for more than 12 months generally will result in a recognition of long-term capital gain or loss. However, the recapturable portions of depreciation, depletion and intangible drilling costs will be ordinary income regardless of how long you have owned your units. If the units are held for 12 months or less, the gain or loss generally will be short-term gain or loss. Also, your pro rata share of your partnership's liabilities, if any, as of the date of the sale or exchange must be included in the amount realized. Therefore, the gain recognized may result in a tax liability to you greater than the cash proceeds, if any, received by you from the disposition. In addition to gain from a passive activity, a portion of any gain recognized by a limited partner on the sale or other disposition of his units may be characterized as portfolio income. A gift of your units may result in federal and/or state income tax and gift tax liability to you. Also, interests in different partnerships do not qualify for tax-free like-kind exchanges. Other dispositions of your units may or may not result in recognition of taxable gain. However, no gain should be recognized by an investor general partner on the conversion of his investor general partner units to limited partner units so long as there is no change in his share of his partnership's liabilities or certain partnership assets as a result of the conversion. In addition, if you sell or exchange all or part of your units you are required by the Internal Revenue Code to notify your partnership within 30 days or by January 15 of the following year, if earlier. You are urged to consult with your tax advisor before you make any disposition of your units, including purchase of the units by the managing general partner. Minimum Tax - Tax Preferences With limited exceptions, all taxpayers are subject to the alternative minimum tax. If your alternative minimum tax exceeds your regular tax, then the excess is payable in addition to the regular tax. The alternative minimum tax is intended to insure that no one with substantial income can avoid tax liability by using deductions and credits. The alternative minimum tax accomplishes this objective by not treating favorably certain items that are treated favorably for purposes of the regular tax, including the deductions for intangible drilling costs and accelerated depreciation except as discussed above in "-Depreciation - -Modified Accelerated Cost Recovery System ("MACRS")." Generally, the alternative minimum tax rate for individuals is 26% on alternative minimum taxable income up to $175,000, $87,500 for married individuals filing separate returns, and 28% thereafter. The tax rates on capital gains also apply for purposes of the alternative minimum tax. Regular tax personal exemptions are not available for purposes of the alternative minimum tax. However, alternative minimum taxable income may be reduced by certain itemized deductions, exemption amounts, and net operating losses. Under the Jobs and Growth Tax Relief Reconciliation Act of 2003, for tax years 2003 and 2004, the exemption amount from alternative minimum tax is increased from $49,000 to $58,000 for married couples filing jointly and surviving spouses; from $35,750 to $40,250 for single filers, and from $24,500 to $29,000 for married persons filing separately. After 2004, the exemption amount for individuals is $45,000 for married couples filing jointly and surviving spouses, $33,750 for single filers, and $22,500 for married persons filing separately. These exemption amounts are reduced by 25% of the alternative minimum taxable income in excess of: o $150,000 for joint returns and surviving spouses; o $75,000 for married persons filing separately; and 99 o $112,500 for single taxpayers. Also, for 2003 and 2004, married persons filing separately must increase their alternative minimum taxable income by the lesser of: (i) 25% of the excess of alternative minimum taxable income over $191,000; or (ii) $29,000. After 2004, married individuals filing separately must increase alternative minimum taxable income by the lesser of: (i) 25% of the excess of alternative minimum taxable income over $165,000; or (ii) $22,500. Alternative minimum taxable income generally is taxable income, plus or minus adjustments, plus preferences. For taxpayers other than "integrated oil companies," which term does not include the partnerships, the 1992 National Energy Bill repealed the preferences for: o excess intangible drilling costs; and o excess percentage depletion for natural gas and oil. The repeal of the excess intangible drilling costs preference, however, may not result in more than a 40% reduction in the amount of the taxpayer's alternative minimum taxable income computed as if the excess intangible drilling costs preference had not been repealed. Under the prior rules, the amount of intangible drilling costs which is not deductible for alternative minimum tax purposes is the excess of the "excess intangible drilling costs" over 65% of net income from natural gas and oil properties. Excess intangible drilling costs is the regular intangible drilling costs deduction minus the amount that would have been deducted under 120-month straight-line amortization, or, at the taxpayer's election, under the cost depletion method. There is no preference item for costs of nonproductive wells. Also, you may elect to capitalize all or part of your share of your partnership's intangible drilling costs and deduct the costs ratably over a 60-month period beginning with the month in which the costs were paid or incurred. This election also applies for regular tax purposes and can be revoked only with the IRS' consent. Making this election, therefore, generally will result in the following consequences to you: o your regular tax deduction for intangible drilling costs in the year in which you invest will be reduced because you must spread the deduction for the amount of intangible drilling costs which you elect to capitalize over the 60-month amortization period; and o the capitalized intangible drilling costs will not be treated as a preference that is included in your alternative minimum taxable income. The likelihood of you incurring, or increasing, any alternative minimum tax liability because of an investment in a partnership must be determined on an individual basis, and you are urged to consult with your personal tax advisor. Limitations on Deduction of Investment Interest Investment interest expense is deductible by a noncorporate taxpayer only to the extent of net investment income each year, with an indefinite carryforward of disallowed amounts. An investor general partner's share of any interest expense incurred by his partnership before his investor general partner units are converted to limited partner units will be subject to the investment interest limitation. In addition, an investor general partner's income and losses, including intangible drilling costs, from his partnership will be considered investment income and losses. Losses allocable to an investor general partner will reduce his net investment income and may affect the deductibility of his investment interest expense, if any. These rules do not apply to partnership income or expense subject to the passive activity loss limitations for limited partners. Allocations The partnership agreement allocates to you your share of your partnership's income, gains, losses and deductions, including the deductions for intangible drilling costs and depreciation. Your capital account will be adjusted to reflect these allocations 100 and your capital account, as adjusted, will be given effect in distributions made to you on liquidation of the partnership or your interest in the partnership. Generally, your capital account will be: o increased by the amount of money you contribute to the partnership and allocations to you of income and gain; and o decreased by the value of property or cash distributed to you and allocations to you of loss and deductions. It should be noted that your share of your partnership's items of income, gain, loss, and deduction must be taken into account by you whether or not there is any distributable cash. Your share of partnership revenues applied by your partnership to the repayment of loans or the reserve for plugging wells, for example, will be included in your gross income in a manner analogous to an actual distribution of the income to you. Thus, you may have tax liability on taxable income from your partnership for a particular year in excess of any cash distributions from the partnership to you with respect to that year. To the extent a partnership has cash available for distribution, however, it is the managing general partner's policy that partnership distributions will not be less than the managing general partner's estimate of the investors' income tax liability with respect to that partnership's income. If any allocation under the partnership agreement is not recognized for federal income tax purposes, your share of the items subject to that allocation generally will be determined in accordance with your interest in the partnership in which you invest, determined by considering relevant facts and circumstances. To the extent the deductions allocated by the partnership agreement exceed deductions which would be allowed under a reallocation by the IRS, you may incur a greater tax burden. Partnership Borrowings Under the partnership agreement the managing general partner and its affiliates may make loans to the partnerships. The use of partnership revenues taxable to you to repay borrowings by your partnership could create income tax liability for you in excess of your cash distributions from the partnership, since repayments of principal are not deductible for federal income tax purposes. In addition, interest on the loans will not be deductible unless the loans are bona fide loans that will not be treated as capital contributions in light of all the surrounding facts and circumstances. Partnership Organization and Offering Costs Expenses connected with the sale of the units in the partnerships, including the dealer-manager fee and sales commissions paid to the dealer-manager which are charged under the partnership agreement 100% to the managing general partner as organization and offering costs, are not deductible. Although certain organization expenses of the partnerships may be amortized over a period of not less than 60 months, these expenses are also paid by the managing general partner as part of each partnership's organization and offering costs. Thus, any related deductions, which the managing general partner does not expect will be material in amount, will be allocated to the managing general partner. Tax Elections Each partnership may elect to adjust the basis of its partnership property on the transfer of a unit in the partnership by sale or exchange or on the death of an investor, and on the distribution of property by the partnership to a partner. The general effect of this election is that transferees of the units are treated, for purposes of depreciation and gain, as though they had acquired a direct interest in the partnership assets and the partnership is treated for these purposes, on certain distributions to partners, as though it had newly acquired an interest in the partnership assets and therefore acquired a new cost basis for the assets. Also, certain "start-up expenditures" must be capitalized and can be amortized only over a 60-month period. If it is ultimately determined that any of a partnership's expenses constituted start-up expenditures and not deductible business expenses, the partnership's deductions for those expenses would be deferred over the 60-month period. Disallowance of Deductions under Section 183 of the Internal Revenue Code Your ability to deduct your share of your partnership's losses could be lost if the partnership lacks the appropriate profit motive. There is a presumption under the Internal Revenue Code that an activity is engaged in for profit if, in any three of 101 five consecutive taxable years, the gross income derived from the activity exceeds the deductions attributable to the activity. Thus, if your partnership fails to show a profit in at least three of five consecutive years this presumption will not be available and the possibility that the IRS could successfully challenge the partnership deductions claimed by you would be substantially increased. The fact that the possibility of ultimately obtaining profits is uncertain, standing alone, does not appear to be sufficient grounds for the denial of losses. In this regard, special counsel has expressed the opinion that the partnerships will possess the requisite profit motive. This opinion assumes that each investor has an objective to carry on the business of the partnership in which he invests for profit, and is based in part on the results of the previous partnerships sponsored by the managing general partner set forth in "Prior Activities" and the managing general partner's representations that each partnership will be operated as described in this prospectus and the principal purpose of each partnership is to locate, produce and market natural gas and oil on a profitable basis apart from tax benefits (which is supported by the geological evaluations and other information for the proposed prospects for Atlas America Public #12-2003 Limited Partnership included in Appendix A to this prospectus). Termination of a Partnership A partnership will be considered as terminated for federal income tax purposes if within a 12 month period there is a sale or exchange of 50% or more of the total interest in partnership capital and profits. In that event, you would realize taxable gain to the extent that money regarded as distributed to you by your partnership exceeds the adjusted basis of your units. The conversion of investor general partner units to limited partner units, however, will not terminate a partnership. Lack of Registration as a Tax Shelter An organizer of a "tax shelter" must obtain an identification number which must be included on the tax returns of investors in the tax shelter. For this purpose, a "tax shelter" includes an investment with respect to which any person could reasonably infer that the ratio that the aggregate amount of the potentially allowable deductions and 350% of the potentially allowable credits with respect to the investment during the first five years of the investment bears to the amount of money and the adjusted basis of property contributed to the investment exceeds 2 to 1. In this regard, the managing general partner has determined that none of the partnerships has a tax shelter ratio greater than 2 to 1. Accordingly, the managing general partner does not intend to register any of the partnerships with the IRS as a tax shelter. If it is subsequently determined by the IRS or the courts that the partnership in which you invest was required to be registered with the IRS as a tax shelter, the managing general partner would be subject to certain penalties, and you would be liable for a $250 penalty for failure to include a tax shelter registration number for your partnership on your tax return unless the failure was due to reasonable cause. You also would be liable for a penalty of $100 for failing to furnish the tax shelter registration number to any transferee of your units. However, special counsel has expressed the opinion that none of the partnerships is required to register with the IRS as a tax shelter. This opinion is based in part on the managing general partner's representations that none of the partnerships has a tax shelter ratio greater than 2 to 1 and each partnership will be operated as described in this prospectus. Issuance of a registration number does not indicate that an investment or the claimed tax benefits have been reviewed, examined, or approved by the IRS. Investor Lists. If requested by the IRS, each partnership must identify its investors and give the IRS certain information concerning each investor's partnership investment and tax benefits. Tax Returns and Audits In General. The tax treatment of all partnership items generally is determined at the partnership, rather than the partner, level; and the partners generally are required to treat partnership items on their individual returns in a manner which is consistent with the treatment of the partnership items on the partnership return. Generally, the IRS must conduct an administrative determination as to partnership items at the partnership level before conducting deficiency proceedings against 102 a partner, and the partners must file a request for an administrative determination before filing suit for any credit or refund. The period for assessing tax against you and the other investors attributable to a partnership item may be extended by agreement between the IRS and the managing general partner, which will serve as each partnership's representative in all administrative and judicial proceedings conducted at the partnership level. The managing general partner generally may enter into a settlement on behalf of, and binding on, any investor owning less than a 1% profits interest if the partnership has more than 100 partners. In addition, a partnership with at least 100 partners may elect to be governed under simplified tax reporting and audit rules as an "electing large partnership." These rules also facilitate the matching of partnership items with individual partner tax returns by the IRS. The managing general partner does not anticipate that the partnerships will make this election. By executing the partnership agreement, you agree that you will not form or exercise any right as a member of a notice group and will not file a statement notifying the IRS that the managing general partner does not have binding settlement authority. Tax Returns. Your income tax returns are your responsibility. The partnership in which you invest will provide you with the tax information applicable to your investment in the partnership necessary to prepare your tax returns. Penalties and Interest In General. Interest is charged on underpayments of tax and various civil and criminal penalties are included in the Internal Revenue Code. Penalty for Negligence or Disregard of Rules or Regulations. If any portion of an underpayment of tax is attributable to negligence or disregard of rules or regulations, 20% of that portion is added to the tax. Negligence is strongly indicated if you fail to treat partnership items on your tax return in a manner that is consistent with the treatment of those items on your partnership's return or to notify the IRS of the inconsistency. Valuation Misstatement Penalty. There is an addition to tax of 20% of the amount of any underpayment of tax of $5,000 or more which is attributable to a substantial valuation misstatement. There is a substantial valuation misstatement if: o the value or adjusted basis of any property claimed on a return is 200% or more of the correct amount; or o the price for any property or services, or for the use of property, claimed on a return is 200% or more, or 50% or less, of the correct price. If there is a gross valuation misstatement, which is 400% or more of the correct value or adjusted basis or the undervaluation is 25% or less of the correct amount, then the penalty is 40%. Substantial Understatement Penalty. There is also an addition to tax of 20% of any underpayment if the difference between the tax required to be shown on the return over the tax actually shown on the return exceeds the greater of: o 10% of the tax required to be shown on the return; or o $5,000. The amount of any understatement generally will be reduced to the extent it is attributable to the tax treatment of an item: o supported by substantial authority; or o adequately disclosed on the taxpayer's return and there was a reasonable basis for the tax treatment. However, in the case of "tax shelters," which includes each partnership for this purpose, the understatement may be reduced only if the tax treatment of an item attributable to a tax shelter was supported by substantial authority and the taxpayer establishes that he reasonably believed that the tax treatment claimed was more likely than not the proper treatment. 103 IRS Anti-Abuse Rules and Judicial Doctrines. If a principal purpose of a partnership is to reduce substantially the partners' federal income tax liability in a manner that is inconsistent with the intent of the partnership rules of the Internal Revenue Code, based on all the facts and circumstances, the IRS is authorized to remedy the abuse. In addition, special counsel has considered the possible application to the partnerships and their intended activities of all potentially relevant judicial doctrines including step transactions, business purpose, economic substance, substance over form, and sham transaction doctrines. The gist of these judicial doctrines is that tax deductions from a transaction will be disallowed if the transaction has no economic substance apart from the tax benefits. Special counsel has expressed the opinion that these anti-abuse rules and judicial doctrines will not have a material adverse effect on the tax consequences of an investment in a partnership by a typical investor as described in special counsel's opinions. This opinion assumes that each investor has an objective to carry on the business of the partnership in which he invests for profit, and is based in part on the results of the previous partnerships sponsored by the managing general partner set forth in "Prior Activities" and the managing general partner's representations that each partnership will be operated as described in this prospectus and the principal purpose of each partnership is to locate, produce and market natural gas and oil on a profitable basis apart from tax benefits (which is supported by the geological evaluations and other information for the proposed prospects for Atlas America Public #12-2003 Limited Partnership included in Appendix A to this prospectus). State and Local Taxes Under Pennsylvania law each partnership is required to withhold state income tax at the rate of 2.8% on any Pennsylvania taxable income allocable from the partnership to its investors who are not residents of Pennsylvania. Also, your partnership will operate in states and localities which impose a tax on its assets or its income, or on you. Deductions which are available to you for federal income tax purposes may not be available for state or local income tax purposes. You are urged to consult with your own tax advisors concerning the possible effect of various state and local taxes on your personal tax situation. Severance and Ad Valorem (Real Estate) Taxes Each partnership may incur various ad valorem or severance taxes imposed by state or local taxing authorities. Social Security Benefits and Self-Employment Tax A limited partner's share of income or loss from a partnership is excluded from the definition of "net earnings from self-employment." No increased benefits under the Social Security Act will be earned by limited partners, and if any limited partners are currently receiving Social Security benefits their shares of partnership taxable income will not be taken into account in determining any reduction in benefits because of "excess earnings." An investor general partner's share of income or loss from a partnership will constitute "net earnings from self-employment" for these purposes. The ceiling for social security tax of 12.4% in 2003 is $87,000 and the ceiling for 2004 is not yet known. There is no ceiling for medicare tax of 2.9%. Self-employed individuals can deduct one-half of their self-employment tax. Farmouts Under a farmout by a partnership, if a property interest, other than an interest in the drilling unit assigned to the partnership well in question, is earned by the farmee (anyone other than the partnership) from the farmor (the partnership) as a result of the farmee drilling or completing the well, then the farmee must recognize income equal to the fair market value of the outside interest earned, and the farmor must recognize gain or loss on a deemed sale equal to the difference between the fair market value of the outside interest and the farmor's tax basis in the outside interest. Neither the farmor nor the farmee would have received any cash to pay the tax. The managing general partner will attempt to eliminate or reduce any gain to the partnership from a farmout, if any. However, if the IRS claims that a farmout by a partnership results in taxable income to the partnership and its position is ultimately sustained, you and the other investors in that partnership would be required to include your share of the resulting taxable income on your respective personal income tax returns, even though the partnership and you and the other investors received no cash from the farmout. 104 Foreign Partners Each partnership generally will be required to withhold and pay income tax to the IRS at the highest rate under the Internal Revenue Code applicable to partnership income allocable to its foreign partners, even if no cash distributions are made to them. In the event of overwithholding a foreign partner must file a United States tax return to obtain a refund. Under the Internal Revenue Code, for withholding purposes, a foreign partner means a partner who is a nonresident alien individual or a foreign corporation, partnership, trust or estate, if the partner has not certified to the partnership the partner's nonforeign status. Estate and Gift Taxation There is no federal tax on lifetime or testamentary transfers of property between spouses. The gift tax annual exclusion in 2003 is $11,000 per donee which will be adjusted in subsequent years for inflation. Under the Economic Growth and Tax Relief Reconciliation Act of 2001 ("the 2001 Tax Act") estates of $1 million in 2003 and $1.5 million in 2004, which further increases in stages to $3.5 million by 2009, or less generally are not subject to federal estate tax. Under the 2001 Tax Act, the federal estate tax is scheduled to be repealed in 2010, and then reinstated in 2011 under the rules in effect before the 2001 Tax Act was enacted. Changes in the Law Your investment in a partnership may be affected by changes in the tax laws. For example, under the Jobs and Growth Tax Relief Reconciliation Act of 2003, the top four federal income tax brackets for individuals have been reduced, including reducing the top bracket to 35% from 38.6%. These changes are retroactive to January 1, 2003, and are scheduled to expire December 31, 2010. The lower federal income tax rates will reduce to some degree the amount of taxes you save by virtue of your share of your partnership's deductions for intangible drilling costs, depletion and depreciation. However, the lower federal income tax rates also will reduce the amount of federal income tax liability incurred by you on your share of the net income of your partnership. There is no assurance that the federal income tax rates discussed above will not be changed again in the future. SUMMARY OF PARTNERSHIP AGREEMENT The rights and obligations of the managing general partner and you and the other investors are governed by the form of partnership agreement, a copy of which is attached as Exhibit (A) to this prospectus. You are urged to not invest in a partnership without first thoroughly reviewing the partnership agreement. The following is a summary of the material provisions in the partnership agreement that are not covered elsewhere in this prospectus. Thus, this prospectus summarizes all of the material provisions of the partnership agreement. Liability of Limited Partners Each partnership will be governed by the Delaware Revised Uniform Limited Partnership Act. If you invest as a limited partner, then generally you will not be liable to third-parties for the obligations of your partnership unless you: o also invest as an investor general partner; o take part in the control of the partnership's business in addition to the exercise of your rights and powers as a limited partner; or o fail to make a required capital contribution to the extent of the required capital contribution. In addition, you may be required to return any distribution you receive if you knew at the time the distribution was made that it was improper because it rendered the partnership insolvent. Amendments Amendments to the partnership agreement of a partnership may be proposed in writing by: 105 o the managing general partner and adopted with the consent of investors whose units equal a majority of the total units in the partnership; or o investors whose units equal 10% or more of the total units in the partnership and adopted by an affirmative vote of investors whose units equal a majority of the total units in the partnership. The partnership agreement of each partnership may also be amended by the managing general partner without the consent of the investors for certain limited purposes. However, an amendment that materially and adversely affects the investors can only be made with the consent of the affected investors. Notice The following provisions apply regarding notices: o when the managing general partner gives you and other investors notice it begins to run from the date of mailing the notice and is binding even if it is not received; o the notice periods are frequently quite short, a minimum of 22 calendar days, and apply to matters that may seriously affect your rights; and o if you fail to respond in the specified time to the managing general partner's second request for approval of or concurrence in a proposed action, then you will conclusively be deemed to have approved the action unless the partnership agreement expressly requires your affirmative approval. Voting Rights Other than as set forth below, you generally will not be entitled to vote on any partnership matters at any partnership meeting. However, at any time investors whose units equal 10% or more of the total units in a partnership may call a meeting to vote, or vote without a meeting, on the matters set forth below without the concurrence of the managing general partner. On the matters being voted on you are entitled to one vote per unit or if you own a fractional unit that fraction of one vote equal to the fractional interest in the unit. Investors whose units equal a majority of the total units in a partnership may vote to: o dissolve the partnership; o remove the managing general partner and elect a new managing general partner; o elect a new managing general partner if the managing general partner elects to withdraw from the partnership; o remove the operator and elect a new operator; o approve or disapprove the sale of all or substantially all of the partnership assets; o cancel any contract for services with the managing general partner, the operator, or their affiliates without penalty on 60 days notice; and o amend the partnership agreement; provided however, any amendment may not: o without the approval of you or the managing general partner increase the duties or liabilities of you or the managing general partner or increase or decrease the profits or losses or required capital contribution of you or the managing general partner; or 106 o without the unanimous approval of all investors in the partnership affect the classification of partnership income and loss for federal income tax purposes. The managing general partner, its officers, directors, and affiliates may also subscribe for units in each partnership on a discounted basis, and they may vote on all matters other than: o the issues set forth above concerning removing the managing general partner and operator; and o any transaction between the managing general partner or its affiliates and the partnership. Any units owned by the managing general partner and its affiliates will not be included in determining the requisite number of units necessary to approve any partnership matter on which the managing general partner and its affiliates may not vote or consent. Access to Records You will have access to all records of your partnership at any reasonable time on adequate notice. However, logs, well reports, and other drilling and operating data may be kept confidential for reasonable periods of time. Your ability to obtain the list of investors is subject to additional requirements set forth in the partnership agreement. Withdrawal of Managing General Partner After 10 years the managing general partner may voluntarily withdraw as managing general partner of a partnership for any reason by giving 120 days' written notice to you and the other investors in the partnership. Although the withdrawing managing general partner is not required to provide a substitute managing general partner, a new managing general partner may be substituted by the affirmative vote of investors whose units equal a majority of the total units in the partnership. If the investors, however, choose not to continue the partnership and select a substitute managing general partner, then the partnership would terminate and dissolve which could result in adverse tax and other consequences to you. Also, subject to a required participation of not less than 1% of each partnership's revenues, the managing general partner may partially withdraw a property interest in the partnership's wells equal to or less than its revenue interest if the withdrawal is: o to satisfy the bona fide request of its creditors; or o approved by investors in the partnership whose units equal a majority of the total units. Return of Subscription Proceeds if Funds Are Not Invested in Twelve Months Although the managing general partner anticipates that each partnership will spend all the subscription proceeds soon after the offering of the partnership closes, each partnership will have 12 months in which to use or commit funds to drilling activities. If within the 12-month period the partnership has not used or committed for use all the subscription proceeds, then the managing general partner will distribute the remaining subscription proceeds to you and the other investors in the partnership in accordance with your subscription proceeds as a return of capital. SUMMARY OF DRILLING AND OPERATING AGREEMENT The managing general partner will serve as the operator under the drilling and operating agreement, Exhibit (II) to the partnership agreement. The operator may be replaced at any time on 60 days' advance written notice by the managing general partner acting on behalf of a partnership on the affirmative vote of investors whose units equal a majority of the total units in the partnership. You are urged not to invest in a partnership without first thoroughly reviewing the drilling and operating agreement. The following is a summary of the material provisions in the drilling and operating agreement that are not covered elsewhere in this prospectus. Thus, this prospectus summarizes all of the material provisions of the drilling and operating agreement. 107 The drilling and operating agreement includes a number of material provisions, including, without limitation, those set forth below. o The operator's right to resign after five years. o The operator's right beginning one year after a partnership well begins producing to retain $200 per month to cover future plugging and abandonment costs of the well, although the managing general partner historically has never done this after only one year. o The grant of a first lien and security interest in the wells and related production to secure payment of amounts due to the operator by a partnership. o The prescribed insurance coverage to be maintained by the operator. o Limitations on the operator's authority to incur extraordinary costs with respect to producing wells in excess of $5,000 per well. o Restrictions on the partnership's ability to transfer its interest in fewer than all wells unless the transfer is of an equal undivided interest in all wells. o The limitation of the operator's liability to a partnership except for the operator's: o violations of law; o negligence or misconduct by it, its employees, agents or subcontractors; or o breach of the drilling and operating agreement. o The excuse for nonperformance by the operator due to force majeure which generally means acts of God, catastrophes and other causes which preclude the operator's performance and are beyond its control. REPORTS TO INVESTORS Under the partnership agreement for each partnership you and certain state securities commissions will be provided the reports and information set forth below for your partnership, which your partnership will pay as a direct cost. o Beginning with the calendar year in which your partnership closes, you will be provided an annual report within 120 days after the close of the calendar year, and beginning with the following calendar year, a report within 75 days after the end of the first six months of its calendar year, containing at least the following information. o Audited financial statements of the partnership prepared on an accrual basis in accordance with generally accepted accounting principles with a reconciliation with respect to information furnished for income tax purposes. Independent certified public accountants will audit the financial statements to be included in the annual report. Semiannual reports will not be audited. o A summary of the total fees and compensation paid by the partnership to the managing general partner, the operator, and their affiliates, including the percentage that the annual unaccountable, fixed payment reimbursement for administrative costs bears to annual partnership revenues. 108 o A description of each prospect owned by the partnership, including the cost, location, number of acres, and the interest. o A list of the wells drilled or abandoned by the partnership indicating: o whether each of the wells has or has not been completed; and o a statement of the cost of each well completed or abandoned. o A description of all farmouts, farmins, and joint ventures. o A schedule reflecting: o the total partnership costs; o the costs paid by the managing general partner and the costs paid by the investors; o the total partnership revenues; and o the revenues received or credited to the managing general partner and the revenues received or credited to you and the other investors. o On request the managing general partner will provide you the information specified by Form 10-Q (if that report is required to be filed with the SEC) within 45 days after the close of each quarterly fiscal period. Also, this information is available at the SEC website www.sec.gov. o By March 15 of each year you will receive the information that is required for you to file your federal and state income tax returns. o Beginning with the second calendar year after your partnership closes, and every year thereafter, you will receive a computation of the partnership's total natural gas and oil proved reserves and its dollar value. The reserve computations will be based on engineering reports prepared by the managing general partner and reviewed by an independent expert. PRESENTMENT FEATURE Beginning with the fifth calendar year after your partnership closes you and the other investors in your partnership may present your units to the managing general partner to purchase your units. However, you are not required to offer your units to the managing general partner, and you may receive a greater return if you retain your units. The managing general partner will not purchase less than one unit unless the fractional unit represents your entire interest. The managing general partner has no obligation and does not intend to establish a reserve to satisfy the presentment obligation and may immediately suspend its purchase obligation by notice to you if it determines, in its sole discretion, that it: o does not have the necessary cash flow; or o cannot borrow funds for this purpose on terms it deems reasonable. If fewer than all units presented at any time are to be purchased by the managing general partner, then the units to be purchased will be selected by lot. 109 The managing general partner's obligation to purchase the units presented may be discharged for its benefit by a third-party or an affiliate. If you sell your unit it will be transferred to the party who pays for it, and you will be required to deliver an executed assignment of your unit along with any other documents that the managing general partner requests. Your presentment is subject to the following conditions: o the managing general partner will not purchase more than 5% of the units in a partnership in any calendar year; o the presentment must be within 120 days of the partnership reserve report discussed below; o in accordance with Treas. Reg.ss.1.7704-1(f) the purchase may not be made by the managing general partner until at least 60 calendar days after you notify the partnership in writing of your intent to present your unit; and o the purchase will not be considered effective until the presentment price has been paid to you in cash. The amount attributable to a partnership's natural gas and oil reserves will be determined based on the last reserve report. Beginning with the second calendar year after your partnership closes and every year thereafter, the managing general partner will estimate the present worth of future net revenues attributable to your partnership's interest in proved reserves. In making this estimate, the managing general partner will use: o a 10% discount rate; o a constant oil price; and o base natural gas prices on the existing natural gas contracts at the time of the presentment. Your presentment price will be based on your share of your partnership's net assets and liabilities as described below, based on the ratio that the number of your units bears to the total number of units in your partnership. The presentment price will include the sum of the following partnership items: o an amount based on 70% of the present worth of future net revenues from the proved reserves determined as described above; o cash on hand; o prepaid expenses and accounts receivable, less a reasonable amount for doubtful accounts; and o the estimated market value of all assets not separately specified above, determined in accordance with standard industry valuation procedures. There will be deducted from the foregoing sum the following items: o an amount equal to all debts, obligations, and other liabilities, including accrued expenses; and o any distributions made to you between the date of the request and the actual payment. However, if any cash distributed was derived from the sale, after the presentment request, of oil, natural gas, or a producing property, for purposes of determining the reduction of the presentment price the distributions will be discounted at the same rate used to take into account the risk factors employed to determine the present worth of the partnership's proved reserves. 110 The amount may be further adjusted by the managing general partner for estimated changes from the date of the reserve report to the date of payment of the presentment price to you because of the following: o the production or sales of, or additions to, reserves and lease and well equipment, sale or abandonment of leases, and similar matters occurring before the presentment request; and o any of the following occurring before payment of the presentment price to you; o changes in well performance; o increases or decreases in the market price of oil, natural gas, or other minerals; o revision of regulations relating to the importing of hydrocarbons; and o changes in income, ad valorem, and other tax laws such as material variations in the provisions for depletion; and o similar matters. As of January 1, 2003, fewer than 35 units have been presented to the managing general partner for purchase in its previous 43 limited partnerships. TRANSFERABILITY OF UNITS Restrictions on Transfer Imposed by the Securities Laws, the Tax Laws and the Partnership Agreement Your ability to sell or otherwise transfer your units in your partnership is restricted by the securities laws, the tax laws, and the partnership agreement as described below. First, under the tax laws you will not be able to sell, assign, exchange, or transfer your unit if it would, in the opinion of counsel for the partnership, result in the following: o the termination of your partnership for tax purposes; or o your partnership being treated as a "publicly-traded" partnership for tax purposes. Second, under the partnership agreement transfers are subject to the following limitations: o the partnership will recognize the transfer of only one or more whole units unless you own less than a whole unit, in which case your entire fractional interest must be transferred; o the costs and expenses associated with the transfer must be paid by the person transferring the unit; o the form of transfer must be in a form satisfactory to the managing general partner; and o the terms of the transfer must not contravene those of the partnership agreement. Your transfer of a unit will not relieve you of your responsibility for any obligations related to the units under the partnership agreement. Also, the transfer does not grant rights under the partnership agreement as among your transferees to more than one party unanimously designated by the transferees to the managing general partner. Finally, the transfer of a unit does not require an accounting by the managing general partner. Any transfer when the assignee of the unit does not become a substituted partner as described below in "- Conditions to Becoming a Substitute Partner," will be effective as of: 111 o midnight of the last day of the calendar month in which it is made; or o at the managing general partner's election 7:00 A.M. of the following day. Finally, you will not be able to sell, assign, pledge, hypothecate, or transfer your unit if there is an opinion of counsel for the partnership that the sale, assignment, pledge, hypothecation, or transfer would result in the violation of any applicable federal or state securities laws. Conditions to Becoming a Substitute Partner Under the partnership agreement an assignee of a unit may become a substituted partner only on meeting certain further conditions. The conditions to become a substitute partner are as follows: o the assignor gives the assignee the right; o the assignee pays all costs and expenses incurred in connection with the substitution; and o the assignee executes and delivers the instruments necessary to establish that a legal transfer has taken place and to confirm his agreement to be bound by all terms and provisions of the partnership agreement. A substitute partner is entitled to all of the rights of full ownership of the assigned units, including the right to vote. Each partnership will amend its records at least once each calendar quarter to effect the substitution of substituted partners. PLAN OF DISTRIBUTION Commissions The units in each partnership will be offered on a "best efforts" basis by Anthem Securities, which is an affiliate of the managing general partner, acting as dealer-manager in all states other than Minnesota and New Hampshire and by other selected registered broker/dealers which are members of the NASD acting as selling agents. Anthem Securities was formed for the purpose of serving as dealer-manager of partnerships sponsored by the managing general partner and became an NASD member firm in April, 1997. Bryan Funding, Inc., a member of the NASD, will serve as dealer-manager for the offering in the states of Minnesota and New Hampshire, and will receive the same compensation as Anthem Securities for sales in those states. The term "dealer-manager" as used in this prospectus includes both Anthem Securities, Inc. and Bryan Funding, Inc. The dealer-manager will manage and oversee the offering of the units as described above. Best efforts generally means that the dealer-manager and selling agents will not guarantee that a certain number of units will be sold. Units may also be sold by the officers and directors of the managing general partner in those states where they are licensed or exempt from licensing. Messrs. Kotek, Patel and Atkinson, Ms. Bleichmar and Ms. Black, who are associated with Anthem Securities, will not make any offers or sales under the SEC safe harbor from broker/dealer registration provided by SEC Rule 3a4-1 promulgated under the Securities Exchange Act of 1934 (the "Act"), although they may do so as associated persons of Anthem Securities. Also, all offers and sales of units by the managing general partner's remaining officers and directors will be made under the SEC safe harbor from broker/dealer registration provided by Rule 3a4-1. In this regard, none of the remaining officers and directors of the managing general partner: o is subject to a statutory disqualification, as that term is defined in Section 3(a)(39) of the Act, at the time of his participation; o is compensated in connection with his participation by the payment of commissions or other remuneration based either directly or indirectly on transactions in securities; and o is at the time of his participation an associated person of a broker or dealer. 112 Also, each of the remaining officers and directors: o performs, or is intended primarily to perform at the end of the offering, substantial duties for or on behalf of the managing general partner otherwise than in connection with transactions in securities; o was not a broker or dealer, or an associated person of a broker or dealer, within the preceding 12 months; and o will not participate in selling an offering of securities for any issuer more than once every 12 months, with the understanding that for securities issued pursuant to Rule 415 under Securities Act of 1933, the 12 month period begins with the last sale of any security included within one Rule 415 registration. Subject to the exceptions described below, the dealer-manager will receive on each unit sold: o a 2.5% dealer-manager fee; o a 7% sales commission; o a .5% accountable marketing expense fee; and o a .5% reimbursement of the selling agent's bona fide accountable due diligence expenses. All of the.5% reimbursement of the selling agents' bona fide accountable due diligence expenses and generally all of the 7% sales commission will be reallowed to the selling agents, but only a portion of the .5% accountable marketing expense fee may be reallowed to the selling agents. The .5% accountable marketing expense fee will be used for such items as expenses associated with retail seminars (which do not exceed .5% per unit), which is an example of bona fide accountable marketing expenses which would be reimbursed by the managing general partner to the extent they are approved in advance by the managing general partner. In addition, the dealer-manager or managing general partner may make certain non-cash compensation arrangements (which may exceed the .5% accountable marketing expense fee so long as the offering is made in compliance with Rule 2810 of the NASD Conduct Rules as discussed below) with the registered representatives of the selling agents, such as: o payment or reimbursement by the managing general partner in connection with meetings held by the managing general partner for the purpose of training or education of registered representatives of a selling agent, provided that: o the registered representative obtains the selling agent's prior approval to attend the meeting and attendance by the selling agent's registered representatives is not conditioned by the selling agent on the achievement of a sales target; o the location is appropriate to the purpose of the meeting, which means an office of the managing general partner, or a facility located in the vicinity of the office, or a regional location with respect to regional meetings; o the payment or reimbursement is not applied to the expenses of guests of the registered representative; and o the payment or reimbursement by the managing general partner is not conditioned by the managing general partner on the achievement of a sales target. 113 Non-cash compensation means any form of compensation received in connection with the sale of the units that is not cash compensation, including but not limited to merchandise, gifts and prizes, travel expenses, meals and lodging. The dealer-manager will retain any of the accountable marketing expense fee not reallowed to the selling agents. The managing general partner is also using the services of wholesalers who are employed by it or its affiliates and are registered through Anthem Securities. The wholesalers include four Regional Marketing Directors, Mr. Mark Levy, Mr. Bruce Bundy, Mr. Robert Gourlay and Ms. Vicki Burbridge. Most of the 2.5% dealer-manager fee will be reallowed to the affiliated Regional Marketing Directors for subscriptions obtained through their efforts. The dealer-manager will retain the remainder of the dealer-manager fee not reallowed to the wholesalers. The offering will be made in compliance with Rule 2810 of the NASD Conduct Rules and all compensation, including non-cash compensation, to broker/dealers and wholesalers, regardless of the source, will be limited to 10% of the gross proceeds of the offering plus the .5% reimbursement for bona fide accountable due diligence expenses on each subscription. Also, the offering will be made in compliance with Rule 2810(b)(2)(C) of the NASD Conduct Rules and the broker/dealers and wholesalers will not execute a transaction for the purchase of units in a discretionary account without the prior written approval of the transaction by the customer. Finally, although not anticipated, if the dealer-manager assists in the transfer of units then it will comply with Rule 2810(b)(3)(D) of the NASD Conduct Rules. Subject to the following, you and the other investors will pay $10,000 per unit and generally will share costs, revenues, and distributions in the partnership in which you subscribe in proportion with your respective number of units. However, the subscription price for certain investors will be reduced as set forth below: o the subscription price for the managing general partner, its officers, directors, and affiliates, and investors who buy units through the officers and directors of the managing general partner, will be reduced by an amount equal to the 2.5% dealer-manager fee, the 7% sales commission, the .5% reimbursement for accountable due diligence expenses and the .5% accountable marketing expense fee, which will not be paid with respect to these sales; and o the subscription price for registered investment advisors and their clients, and selling agents and their registered representatives and principals, will be reduced by an amount equal to the 7% sales commission, which will not be paid with respect to these sales. No more than 5% of the total units in each partnership may be sold with the discounts described above. These investors who pay a reduced price for their units generally will share in a partnership's costs, revenues, and distributions on the same basis as the other investors who pay $10,000 per unit. Although the managing general partner and its affiliates may buy up to 10% of the units, they do not currently anticipate buying any units. If they do buy units, then those units will not be applied towards the minimum subscription proceeds required for a partnership to begin operations. After the minimum subscriptions are received in a partnership and the checks have cleared the banking system, the dealer-manager fee, the sales commissions, the .5% accountable marketing expense fee and the .5% reimbursement for accountable due diligence expenses will be paid to the dealer-manager and broker/dealers approximately every two weeks until the offering closes. Indemnification The dealer-manager is an underwriter as that term is defined in the 1933 Act and the sales commissions and dealer-manager fees will be deemed underwriting compensation. The managing general partner and the dealer-manager have agreed to indemnify each other, and it is anticipated that the dealer-manager and each selling agent will agree to indemnify each other against certain liabilities, including liabilities under the 1933 Act. 114 SALES MATERIAL In addition to the prospectus the managing general partner intends to use the following sales material with the offering of the units: o a flyer entitled "Atlas America Public #12-2003 Program"; o an article entitled "Tax Rewards with Oil and Gas Partnerships"; o a brochure of tax scenarios entitled "How an Investment in Atlas America Public #12-2003 Program Can Help Achieve an Investor's Tax Objectives"; o a brochure entitled "Investing in Atlas America Public #12-2003 Program"; o a booklet entitled "Outline of Tax Consequences of Oil and Gas Drilling Programs"; o a brochure entitled "The Appalachian Basin: A Prime Drilling Location Which Commands a Premium"; o a brochure entitled "Investment Insights - Tax Time"; o a brochure entitled "Frequently Asked Questions"; and o possibly other supplementary materials. The managing general partner has not authorized the use of other sales material and the offering of units is made only by means of this prospectus. The sales material is subject to the following: o it must be preceded or accompanied by this prospectus; o it is not complete; o it will not contain any material information which is not also set forth in this prospectus; and o it should not be considered a part of or incorporated into this prospectus or the registration statement of which this prospectus is a part. In addition, supplementary materials, including prepared presentations for group meetings, must be submitted to the state administrators before they are used and their use must either be preceded by or accompanied by a prospectus. Also, all advertisements of, and oral or written invitations to, "seminars" or other group meetings at which the units are to be described, offered, or sold will clearly indicate the following: o that the purpose of the meeting is to offer the units for sale; o the minimum purchase price of the units; o the suitability standards to be employed; and o the name of the person selling the units. Also, no cash, merchandise, or other items of value may be offered as an inducement to you or any prospective investor to attend the meeting. All written or prepared audiovisual presentations, including scripts prepared in advance for oral 115 presentations to be made at the meetings, must be submitted to the state administrators within a prescribed review period. These provisions, however, will not apply to meetings consisting only of the registered representatives of the selling agents. You should rely only on the information contained in this prospectus in making your investment decision. No one is authorized to provide you with information that is different. LEGAL OPINIONS Kunzman & Bollinger, Inc., has issued its opinion to the managing general partner regarding the validity and due issuance of the units including assessibility and its opinion on material tax consequences to individual typical investors in the partnerships. However, the factual statements in this prospectus are those of the managing general partner, and counsel has not given any opinions with respect to any of the tax or other legal aspects of this offering except as expressly set forth above. EXPERTS The financial statements included in this prospectus for the managing general partner as of and for the years ended September 30, 2002 and 2001 and the balance sheet for Atlas America Public #12-2003 Limited Partnership as of July 21, 2003 have been audited by Grant Thornton LLP, as of the dates indicated in its reports which appear elsewhere in this prospectus. These financial statements have been included in reliance on its reports given on its authority as experts in auditing and accounting. The geologic evaluation for each of the areas where potential prospects have been identified of United Energy Development Consultants, Inc., which is not affiliated with the managing general partner and its affiliates, appearing in this prospectus has been included in this prospectus on the authority of United Energy Development Consultants, Inc. as an expert with respect to the matters covered by the report and in the giving of the report. References in this prospectus to Wright & Company, Inc. and its reserve and economic report effective September 30, 2002 relating to the oil and gas reserves of Resource America, Inc. are made in reliance on Wright & Company, Inc.'s authority as an expert in petroleum consulting. LITIGATION The managing general partner knows of no litigation pending or threatened to which the managing general partner or the partnerships are subject or may be a party, which it believes would have a material adverse effect on the partnerships or their business, and no such proceedings are known to be contemplated by governmental authorities or other parties. FINANCIAL INFORMATION CONCERNING THE MANAGING GENERAL PARTNER AND ATLAS AMERICA PUBLIC #12-2003 LIMITED PARTNERSHIP Financial information concerning the managing general partner and the first partnership in the program, Atlas America Public #12-2003 Limited Partnership, which is the only partnership that has been formed, is reflected in the following financial statements. The securities offered by this prospectus are not securities of, nor are you acquiring an interest in the managing general partner, its affiliates, or any other entity other than the partnership in which you purchase units. 116 Audit report Atlas America Public #12-2003 Limited Partnership (A Delaware Limited Partnership) July 21, 2003 117 REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS To the Partners Atlas America Public #12-2003 Limited Partnership (A Delaware Limited Partnership) We have audited the accompanying balance sheet of Atlas America Public #12-2003 Limited Partnership (a Delaware Limited Partnership) as of July 21, 2003. This financial statement is the responsibility of the Partnership's management. Our responsibility is to express an opinion on this financial statement based on our audit. We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statement is free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statement. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion. In our opinion, the financial statement referred to above presents fairly, in all material respects, the financial position of Atlas America Public #12-2003 Limited Partnership as of July 21, 2003, in conformity with accounting principles generally accepted in the United States of America. /s/ GRANT THORNTON LLP Cleveland, Ohio July 21, 2003 118 Atlas America Public #12-2003 Limited Partnership (A Delaware Limited Partnership) BALANCE SHEET July 21, 2003
ASSETS Cash $ 100 ------------- PARTNERS' CAPITAL Partners' capital: $ 100 -------------
The accompanying notes are an integral part of this financial statement. 119 Atlas America Public #12-2003 Limited Partnership (A Delaware Limited Partnership) NOTES TO FINANCIAL STATEMENT July 21, 2003 1. ORGANIZATION AND DESCRIPTION OF BUSINESS Atlas America Public #12-2003 Limited Partnership (the "Partnership") is a Delaware Limited Partnership in which Atlas Resources, Inc. ("Atlas") of Pittsburgh, Pennsylvania (a second-tier wholly-owned subsidiary of Atlas America, Inc., which is a second-tier wholly-owned subsidiary of Resource America, Inc., a publicly traded company) will be Managing General Partner and Operator, and subscribers to Units will be either Limited Partners or Investor General Partners depending upon their election. The Partnership will be funded to drill development wells which are proposed to be located primarily in the Clinton/Medina geological formation in western Pennsylvania and eastern Ohio, the Mississippian/ Upper Devonian Sandstone reservoirs in Fayette and Greene Counties, Pennsylvania, and the Upper Devonian Sandstone reservoirs in Armstrong County, Pennsylvania. The Managing General Partner has reserved the right to drill wells in other areas of the Appalachian Basin. Subscriptions at a cost of $10,000 per unit will be sold through wholesalers and broker-dealers including Anthem Securities, Inc., an affiliated company, which will receive, on each unit sold to an investor, a 2.5% dealer-manager fee, a 7% sales commission, a .5% accountable marketing expense fee, and a .5% reimbursement of bona fide accountable due diligence expenses. Commencement of Partnership operations is subject to the receipt of minimum Partnership subscriptions of $1,000,000 (up to a maximum of $75,000,000 for the Atlas America Public #12-2003 Program, which includes this partnership) by December 31, 2003. 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Basis of Accounting The Partnership will prepare its financial statements in accordance with accounting principles generally accepted in the United States of America. Oil and Gas Properties The Partnership will use the successful efforts method of accounting for oil and gas producing activities. Costs to acquire mineral interests in oil and gas properties and to drill and equip wells will be capitalized. Depreciation and depletion will be computed on a field- by-field basis by the unit-of-production method based on periodic estimates of oil and gas reserves. Undeveloped leaseholds and proved properties will be assessed periodically or whenever events or circumstances indicate that the carrying amount of these assets may not be recoverable. Proved properties will be assessed based on estimates of future cash flows. 120 Atlas America Public #12-2003 Limited Partnership (A Delaware Limited Partnership) NOTES TO FINANCIAL STATEMENT - CONTINUED July 21, 2003 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) Use of Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates. 3. FEDERAL INCOME TAXES The Partnership will not be treated as a taxable entity for federal income tax purposes. Any item of income, gain, loss, deduction or credit would flow through to the partners as though each partner has incurred such item directly. As a result, each partner must take into account their pro rata share of all items of partnership income and deductions in computing their federal income tax liability. 4. PARTICIPATION IN REVENUES AND COSTS The Managing General Partner and the other partners will participate in revenues and costs in the following manner:
Managing General Other Partner Partners Partnership costs: Organization and offering costs 100% 0% Lease costs 100% 0% Operating costs, administrative costs, direct costs and all other costs (1) (1) Intangible drilling costs 0% 100% Equipment costs (2) 66% 34% Partnership revenues: Interest income (3) (3) Equipment proceeds (2) 66% 34% Production revenues and other revenues (4)(5) (4)(5) Tax deductions: Intangible drilling and development costs 0% 100% Depreciation (2) 66% 34% Percentage depletion allowances (4)(5)(6) (4)(5)(6)
(1) These costs will be charged to the partners in the same ratio as the related production revenues are credited. (2) These percentages may vary. If the total equipment costs for all of the partnership's wells that would be charged to the other partners exceeds an amount equal to 10% of the subscription proceeds of the other partners in the partnership, then the excess will be charged to the Managing General Partner. Equipment proceeds, if any, will be credited in the same percentage in which the equipment costs were charged. 121 Atlas America Public #12-2003 Limited Partnership (A Delaware Limited Partnership) NOTES TO FINANCIAL STATEMENT - CONTINUED July 21, 2003 4. PARTICIPATION IN REVENUES AND COSTS (Continued) (3) Interest earned on subscription proceeds before the offering closes will be credited to the investor's capital account. After the offering closes and until proceeds from the offering are invested in the partnership's operations any interest income from temporary investments will be allocated pro rata to the investors providing the subscription proceeds. All other interest income, including interest earned on the deposit of operating revenues, will be credited as production revenues are credited. (4) The Managing General Partner and the investors will share in all of the partnership's other revenues in the same percentage as their respective capital contributions bears to the partnership capital contributions except that the Managing General Partner will receive an additional 7.0% of the partnership revenues. However, the Managing General Partner's total revenue share may not exceed 35% of partnership revenues. (5) The actual allocation of partnership revenues between the Managing General Partner and the investors will vary from the allocation described in (4) above if a portion of the Managing General Partner's partnership net production revenues is subordinated. (6) The sharing of the percentage depletion allowance will be in the same percentages as the sharing of the production revenues. 5. TRANSACTIONS WITH ATLAS AND ITS AFFILIATES The Partnership intends to enter into the following significant transactions with Atlas and its affiliates as provided under the Partnership agreement: The partnership will enter into a drilling and operating agreement with Atlas to drill and complete all of the Partnership wells at cost plus 15%. The cost of the wells includes reimbursement to Atlas of its general and administrative overhead cost (approximately $14,000 per well) and all ordinary and actual costs of drilling, testing and completing the wells. Atlas will receive an unaccountable, fixed payment reimbursement for their administrative costs at $75 per well per month, which will be proportionately reduced if the partnership's working interest in a well is less than 100%. Atlas will receive well supervision fees for operating and maintaining the wells during producing operations at a competitive rate (currently the competitive rate is $275 per well per month). The well supervision fees will be proportionately reduced if the partnership's working interest in a well is less than 100%. 122 Atlas America Public #12-2003 Limited Partnership (A Delaware Limited Partnership) NOTES TO FINANCIAL STATEMENT - CONTINUED July 21, 2003 5. TRANSACTIONS WITH ATLAS AND ITS AFFILIATES (Continued) Atlas will charge the partnership a fee for gathering and transportation at a competitive rate (currently in the range of $.29 to $.70 per MCF). Atlas will contribute all the undeveloped leases necessary to cover each of the partnership's prospects and will receive a credit for its capital account in the partnership equal to the cost of the leases (approximately $5,434 per prospect). As the Managing General Partner, Atlas will perform all administrative and management functions for the partnership including billing and collecting revenues and paying expenses. Atlas will be reimbursed for all direct costs expended on behalf of the partnership. 6. PURCHASE COMMITMENT Subject to certain conditions, investor partners may present their interests beginning with the fifth calendar year after the partnership closes for purchase by the Managing General Partner. The Managing General Partner is not obligated to purchase more than 5% of the units in any calendar year. In the event that the Managing General Partner is unable to obtain the necessary funds, the Managing General Partner may suspend its purchase obligation. 7. SUBORDINATION OF MANAGING GENERAL PARTNER'S REVENUE SHARE The Managing General Partner will subordinate up to 50% of its share of production revenues of the Partnership, net of related operating costs, administrative costs and well supervision fees to the receipt by participants of cash distributions from the Partnership equal to at least 10% of their agreed subscriptions, determined on a cumulative basis, in each of the first five 12-month periods beginning with Partnership's first cash distributions from operations. 8. INDEMNIFICATION In order to limit the potential liability of the investor general partners, Atlas has agreed to indemnify each investor general partner from any liability incurred which exceeds such partner's share of Partnership assets. 123 Consolidated audit report Atlas Resources, Inc. and Subsidiary September 30, 2002 and 2001 124 REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS Board of Directors ATLAS RESOURCES, INC. We have audited the accompanying consolidated balance sheets of ATLAS RESOURCES, INC. (a Pennsylvania corporation) and subsidiary as of September 30, 2002 and 2001, and the related consolidated statements of income, comprehensive income, changes in stockholder's equity and cash flows for the years then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of ATLAS RESOURCES, INC. and subsidiary as of September 30, 2002 and 2001, and the results of their operations and their cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America. As discussed in Note 2 to the financial statements, effective October 1, 2001, the Company changed its method of accounting for goodwill for the adoption of SFAS No. 142. /s/ GRANT THORNTON LLP Cleveland, Ohio November 22, 2002 125 ATLAS RESOURCES, INC. AND SUBSIDIARY CONSOLIDATED BALANCE SHEETS SEPTEMBER 30, 2002 AND 2001
2002 2001 ------------- ------------- (in thousands, except share data) ASSETS Current assets: Cash and cash equivalents $ 698 $ 5,358 Accounts receivable 5,419 5,207 Other current assets 320 298 ------------- ------------- Total current assets 6,437 10,863 Property and equipment: Oil and gas properties and equipment (successful efforts) 59,757 44,445 Buildings and land 2,830 2,830 Other 394 392 ------------- ------------- 62,981 47,667 Less - accumulated depreciation, depletion and amortization (10,995) (6,777) ------------- ------------- Net property and equipment 51,986 40,890 Goodwill 20,868 14,479 Intangible assets 4,400 11,278 ------------- ------------- Total assets $ 83,691 $ 77,510 ============= ============= LIABILITIES AND STOCKHOLDER'S EQUITY Current liabilities: Accounts payable $ 3,272 $ 2,901 Deferred revenue on drilling contracts 4,948 17,928 Accrued liabilities 108 83 Advances and note from Parent 51,054 32,895 ------------- ------------- Total current liabilities 59,382 53,807 Commitments and contingencies -- -- Stockholder's equity: Common stock, stated value $10 per share; 500 authorized shares; 200 shares issued and outstanding 2 2 Additional paid-in capital 16,505 16,505 Accumulated other comprehensive (loss) income (212) 10 Retained earnings 8,014 7,186 ------------- ------------- Total stockholder's equity 24,309 23,703 ------------- ------------- $ 83,691 $ 77,510 ============= =============
See accompanying notes to consolidated financial statements 126 ATLAS RESOURCES, INC. AND SUBSIDIARY CONSOLIDATED STATEMENTS OF INCOME YEARS ENDED SEPTEMBER 30, 2002 AND 2001
2002 2001 ------------- ------------- (in thousands) REVENUES Well drilling $ 49,516 $ 32,617 Gas and oil production 10,056 10,622 Well services 5,758 4,431 Other 154 61 ------------- ------------- 65,484 47,731 COSTS AND EXPENSES Well drilling 42,996 26,842 Gas and oil production and exploration 2,178 1,716 Well services 1,108 918 Non-direct 11,122 10,850 Depreciation, depletion and amortization 4,595 4,225 Interest 2,522 1,997 ------------- ------------- 64,521 46,548 ------------- ------------- Income before income taxes 963 1,183 Provision for income taxes 135 455 ------------- ------------- Net income $ 828 $ 728 ============= =============
See accompanying notes to consolidated financial statements 127 ATLAS RESOURCES, INC. AND SUBSIDIARY CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDER'S EQUITY YEARS ENDED SEPTEMBER 30, 2002 AND 2001 (in thousands, except share data)
Common Stock Additional Accumulated Total ------------------------------- Paid-In Comprehensive Retained Stockholder's Shares Amount Capital Income (Loss) Earnings Equity ------------- ------------- ------------- ------------- ------------- ------------- Balance, September 30, 2000 200 $ 2 $ 16,505 $ -- $ 6,458 $ 22,965 Other comprehensive income 10 10 Net income 728 728 ------------- ------------- ------------- ------------- ------------- ------------- Balance, September 30, 2001 200 2 16,505 10 7,186 23,703 Other comprehensive loss (222) (222) Net income 828 828 ------------- ------------- ------------- ------------- ------------- ------------- Balance September 30, 2002 200 $ 2 $ 16,505 $ (212) $ 8,014 $ 24,309 ============= ============= ============= ============= ============= =============
ATLAS RESOURCES, INC. AND SUBSIDIARY CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME YEARS ENDED SEPTEMBER 30, 2002 AND 2001
2002 2001 ------------- ------------- (in thousands) Net income $ 828 $ 728 Cumulative effect of accounting change, net of taxes of $145 -- 241 Derivative losses reclassed into gas production net of taxes of $145 -- (241) Unrealized (loss) gain on natural gas futures and option contracts, net of taxes of $105 and $(5) (222) 10 ------------- ------------- Comprehensive income $ 606 $ 738 ============= =============
See accompanying notes to consolidated financial statements 128 ATLAS RESOURCES, INC. AND SUBSIDIARY CONSOLIDATED STATEMENTS OF CASH FLOWS YEARS ENDED SEPTEMBER 30, 2002 AND 2001
2002 2001 ------------- ------------- (in thousands) CASH FLOWS FROM OPERATING ACTIVITIES: Net income $ 828 $ 728 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization 4,595 4,225 License fees and interest on intercompany note due to Parent 12,399 8,042 Change in operating assets and liabilities: Increase in accounts receivable (212) (7,387) (Increase) decrease in other current assets (22) 77 Decrease in accounts payable and accrued liabilities (1,005) (309) (Decrease) increase in deferred revenue on drilling contracts (12,711) 9,981 ------------- ------------- Net cash provided by operating activities 3,872 15,357 CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures (14,757) (9,072) Decease in other assets -- 20 ------------- ------------- Net cash used in investing activities (14,757) (9,052) CASH FLOWS FROM FINANCING ACTIVITIES: Principal payments on borrowings -- (341) Net advances from (payments to) Parent 6,225 (3,667) ------------- ------------- Net cash provided by (used in) financing activities 6,225 (4,008) ------------- ------------- Increase (decrease) in cash and cash equivalents (4,660) 2,297 Cash and cash equivalents at beginning of year 5,358 3,061 ------------- ------------- Cash and cash equivalents at end of year $ 698 $ 5,358 ============= =============
See accompanying notes to consolidated financial statements 129 ATLAS RESOURCES, INC. AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 1 - NATURE OF OPERATIONS Atlas Resources, Inc. (the "Company"), a Pennsylvania corporation, and its subsidiary, ARD Investments, are engaged in the exploration for development and production of natural gas and oil primarily in the Appalachian Basin Area. In addition, the Company performs contract drilling and well operation services. The Company is a second-tier wholly-owned subsidiary of Atlas America, Inc. (Atlas). Atlas is a second-tier wholly-owned subsidiary of Resource America, Inc.(RAI), a publicly traded company (trading under the symbol REXI on the NASDAQ System) operating in the energy, real estate and financial services sectors. The Company's operations are dependent upon the resources and services provided by Atlas. The Company is also the managing general partner of several oil and gas partnerships. NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Reclassifications Certain reclassifications have been made to the fiscal 2001 consolidated financial statements to conform with the fiscal 2002 presentation. Principles of Consolidation The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiary. The Company also owns individual interests in the assets and is separately liable for its share of liabilities of oil and gas partnerships, whose activities include only exploration and production activities. In accordance with established practice in the oil and gas industry, the Company also includes its pro-rata share of income and expenses of the oil and gas partnerships in which it has an interest. All material intercompany transactions have been eliminated. Use of Estimates Preparation of the financial statements in conformity with accounting principles generally accepted in the United States of America, requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates. Concentration of Credit Risk Financial instruments, which potentially subject the Company to concentrations of credit risk, consist principally of periodic temporary investments of cash. The Company places its temporary cash investments in high quality short-term money market instruments and deposits with high quality financial institutions and brokerage firms. At September 30, 2002 and 2001, the Company had $698,000 and $5.3 million in deposits at various banks, respectively, of which $601,000 and $5.2 million is over the insurance limit of the Federal Deposit Insurance Corporation. No losses have been experienced on such investments. 130 ATLAS RESOURCES, INC. AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Continued) Oil and Gas Properties The Company follows the successful efforts method of accounting. Accordingly, property acquisition costs, costs of successful exploratory wells, all development costs, and the cost of support equipment and facilities are capitalized. Costs of unsuccessful exploratory wells are expensed when such wells are determined to be nonproductive or within twelve months of completion of drilling if this determination cannot be made. The costs associated with drilling and equipping wells not yet completed are capitalized as uncompleted wells, equipment, and facilities. Geological and geophysical costs and the costs of carrying and retaining undeveloped properties, including delay rentals, are expensed as incurred. Production costs, overhead and all exploration costs other than the costs of exploratory drilling are charged to expense as incurred. The Company assesses unproved and proved properties periodically to determine whether there has been a decline in value and, if such decline is indicated a loss is recognized. The assessment of significant unproved properties for impairment is on a property-by-property basis. The Company considers whether a dry hole has been drilled on a portion of the property or in close proximity, the Company's intentions of further drilling, the remaining lease term of the property, and its experience in similar fields in close proximity. The Company assesses unproved properties whose costs are individually insignificant in the aggregate, this assessment includes considering the Company's experience of similar situations, the primary lease terms, the average holding period of unproved properties and the relative proportion of such properties on which proved reserves have been found in the past. The Company compares the carrying value of its proved developed gas and oil producing properties to the estimated future cash flow, net of applicable income taxes, from such properties in order to determine whether their carrying values should be reduced. No adjustment was necessary during any of the fiscal years in the two year period ended September 30, 2002. Upon the sale or retirement of a complete or partial unit of a proved property, the cost and related accumulated depletion are eliminated from the property accounts, and the resultant gain or loss is recognized in the statement of operations. Upon the sale of an entire interest in an unproved property where the property had been assessed for impairment individually, a gain or loss is recognized in the statement of operations. If a partial interest in an unproved property is sold, any funds received are accounted for as a reduction of the cost in the interest retained. On an annual basis, the Company estimates the costs of future dismantlement, restoration, reclamation, and abandonment of its gas and oil producing properties. Additionally, the Company estimates the salvage value of equipment recoverable upon abandonment. At both September 30, 2002 and 2001, the Company's estimate of equipment salvage values was greater than or equal to the estimated costs of future dismantlement, restoration, reclamation, and abandonment. 131 ATLAS RESOURCES, INC. AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Continued) The components of capitalized costs related to the Company's oil and gas producing activities are as follows:
Years Ended September 30, -------------------------- 2002 2001 --------- --------- (in thousands) Mineral Interest in Properties: Proved properties................................................... $ 1 $ 161 Unproved properties................................................. 22 125 Wells and related equipment............................................ 59,484 44,133 Support equipment...................................................... 250 26 --------- ---------- 59,757 44,445 Accumulated depreciation, depletion, amortization and valuation allowances.......................................... (10,506) (6,456) --------- ---------- Net capitalized costs........................................... $ 49,251 $ 37,989 ========= ==========
Revenue Recognition The Company conducts certain energy activities through, and a portion of its revenues are attributable to, sponsored limited partnerships ("Partnerships"). These Partnerships raise money from investors to drill gas and oil wells. The Company serves as general partner of the Partnerships and assumes customary rights and obligations for the Partnerships. As the general partner, the Company is liable for Partnership liabilities and can be liable to limited partners if it breaches its responsibilities with respect to the operations of the Partnerships. The income from the Company's general partner interest is recorded when the gas and oil are sold by a Partnership. The Company also contracts to drill gas and oil wells owned by the Partnerships. The income from a drilling contract relating to a well is recorded upon substantial completion of the well for turnkey contracts and as services are performed for cost-plus contracts. Turnkey contracts are accounted for under the completed contract method. Contracts are considered substantially complete when remaining costs and potential risks are insignificant in amount. The Company determines this on a well-by-well basis to be when the surface equipment has been installed on the well. For contracts for which revenue is recognized as services are performed, the Company uses the value added method (contract value of total work performed at any reporting date) for measuring progress toward the completion of the drilling contract. The Company recognizes transportation revenues at the time the natural gas is delivered to the purchaser. The Company recognizes field services revenues at the time the services are performed. The Company is entitled to receive management fees according to the respective Partnership agreements. The Company recognizes such fees as income when earned and includes them in energy revenues. The Company sells interests in gas and oil wells and retains a working interest and/or overriding royalty. The Company records the income from the working interests and overriding royalties when the gas and oil are sold. Depreciation, Depletion and Amortization The Company amortizes proved gas and oil properties, which include intangible drilling and development costs, tangible well equipment and leasehold costs, on the unit-of-production method using the ratio of current production to the estimated aggregate proved gas and oil reserves. Environmental Matters The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has established procedures for the ongoing evaluation of its operations, to identify potential environmental exposures and to comply with regulatory policies and procedures. The Company accounts for environmental contingencies in accordance with SFAS No. 5 "Accounting for Contingencies." Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, and do not contribute to current or future revenue generation, are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. The Company maintains insurance which may cover in whole or in part certain environmental expenditures. For the years ended September 30, 2002 and 2001, the Company had no environmental matters requiring specific disclosure or requiring recording of a liability. 132 ATLAS RESOURCES, INC. AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Continued) Property and Equipment Property and equipment, other than oil and gas properties, are stated at cost. Depreciation is provided using the straight-line method over the following estimated useful lives once the asset is put into productive use:
Buildings 39 years Other equipment 3 - 7 years
Intangible Assets and Goodwill - Change in Accounting Principle On October 1, 2001, the Company adopted SFAS 142, "Goodwill and Other Intangible Assets," which requires that goodwill no longer be amortized, but instead tested for impairment at least annually. At that time the Company had unamortized goodwill of $14.5 million. The Company has completed the transitional impairment test required upon adoption of SFAS 142. The transitional test, which involved the use of estimates related to the fair market value of the business operations associated with the goodwill did not indicate an impairment loss. The Company will continue to evaluate its goodwill, at least annually, and will charge operations for the impairment of goodwill, if any, in the period in which it is indicated. Changes in the carrying amount of goodwill for the year ended September 30, 2002 are as follows: Year Ended --------------------------------------- 2002 2001 (in thousands) Goodwill at beginning of year (less accumulated amortization of $1,609 and $1,073) $ 14,479 $ 15,015 Amortization of Goodwill -- (536) Syndication network reclassified from other assets in accordance with SFAS 142 (net of accumulated amortization of $711) 6,389 -- ----------- ----------- Goodwill at end of year (net of accumulated amortization of $2,320 and $1,609) $ 20,868 $ 14,479 =========== ===========
For the year ended September 30, 2001 the Company's goodwill amortization expense was approximately $536,000. Adjusted net income for the year ended September 30, 2001 would have been $1.1 million assuming the Company had adopted SFAS 142 effective October 1, 2001. Intangible assets relate primarily to partnership management and operating contracts acquired through acquisitions. The Company amortizes contracts acquired on a straight line method over their respective estimated lives, ranging from five to thirteen years. Amortization expense for the years ended September 30, 2002 and 2001 were $489,000 and $478,000 respectively. The annual amortization expense is approximately $478,000 for each of the succeeding five years.
Year Ended --------------------------------------- 2002 2001 (in thousands) Intangible assets Operating and management contracts $ 6,353 $ 6,353 Syndication rights -- 7,100 ----------- ----------- 6,353 13,453 Accumulated amortization (1,953) (2,175) ----------- ----------- $ 4,400 $ 11,278 =========== ===========
133 ATLAS RESOURCES, INC. AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Continued) Impairment of Long-Lived Assets The Company reviews its long-lived assets for impairment whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset's estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount for that asset to its estimated fair value. Comprehensive Income Comprehensive income includes net income and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources. These changes, other than net income, are referred to as "other comprehensive income" and for the Company represents unrealized hedging gains and losses. Deferred Revenue on Drilling Contracts Funds received that are in excess of costs incurred are classified as a current liability under deferred revenue on drilling contracts. Contract costs include all direct material and labor costs and those indirect costs related to contract performance, such as indirect labor, supplies, repairs and depreciation costs. Income Taxes The Company is included in the consolidated federal income tax return of RAI. Income taxes are presented as if the Company had filed a return on a separate company basis utilizing their calculated effective rate of 14% and 38% for fiscal years 2002 and 2001 respectively. The Company's effective tax rate for fiscal 2002 is lower than the federal statutory rate due to the benefit of percentage depletion and fuel credits. The decrease in the Company's effective tax rate is due to goodwill no longer being amortized and increases in statutory depletion and fuel credits for income tax purposes. Deferred taxes, which are included in Advances from Parent, reflect the tax effect of temporary differences between the tax basis of the Company's assets and liabilities and the amounts reported in the financial statements. Separate company state tax returns are filed in those states in which the Company is registered to do business. Fair Value of Financial Instruments The following methods and assumptions were used by the Company in estimating the fair value of each class of financial instruments for which it is practicable to estimate fair value. For cash and cash equivalents, receivables and payables, the carrying amounts approximate fair value because of the short maturity of these instruments. In fiscal 2001, the Company adopted FASB Statement No. 133, "Accounting for Derivative Instruments and Hedging Activities". Accordingly, natural gas futures and option contracts are recorded at fair value in the Company's consolidated balance sheet. 134 ATLAS RESOURCES, INC. AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Continued) Supplemental Disclosure of Cash Flow Information The Company considers temporary investments with maturity at the date of acquisition of 90 days or less to be cash equivalents.
Years Ended ------------------------------- September 30, 2002 2001 ------------- ------------- (in thousands) Cash paid during the year for: Interest $ 114 $ 96 Income taxes (net of refund) $ -- $ 209
Recently Issued Financial Accounting Standard In June 2001, the Financial Accounting Standards Board ("FASB") issued SFAS No. 143, "Accounting for Asset Retirement Obligations" ("SFAS 143"). SFAS 143 establishes requirements for accounting for removal costs associated with asset retirements. SFAS 143 is effective for fiscal years beginning after June 15, 2002, and will require the Company to record a liability for its retirement obligations with the related transition adjustment reported as a cumulative effect of a change in accounting principle. The Company is currently assessing the impact of this standard on its consolidated financial statements. NOTE 3 - RELATED PARTIES The Company conducts certain energy activities through, and a substantial portion of its revenues are attributable to, limited partnerships ("Partnerships"). The Company serves as general partner of the Partnerships and assumes customary rights and obligations for the Partnerships. As the general partner, the Company is liable for Partnership liabilities and can be liable to limited partners if it breaches its responsibilities with respect to the operations of the Partnerships. The Company is entitled to receive management fees, reimbursement for administrative costs incurred, and to share in the Partnerships' revenue and costs and expenses according to the respective Partnership agreements. The advances from Parent represent amounts owed for advances and transactions in the normal course of business and a note payable to the parent. Other than the note, these advances have no repayment terms and are subordinated to any third-party debt. The note, which is also subordinated to any third-party debt, has a face amount of $15.0 million and accrues interest at an annual rate of 9.50% on any unpaid balances. The principal and any unpaid interest are due upon demand by the Parent. Interest expense related to the note, which is being deferred, was $1.9 million and $1.6 million for the years ended September 30, 2002 and 2001 respectively. The advances have no repayment terms and the note is due on demand. Therefore the Company has classified the amounts due the Parent as a current liability on its Consolidated Balance Sheets. The Parent does not intend to demand payment on the advances or note within the next year. The Company is dependant on its' Parent for management and administrative functions and financing for capital expenditures. The Company pays a management fee to its Parent for management and administrative services, which amounted to $10.5 million and $6.4 million for the years ended September 30, 2002 and 2001, respectively. 135 ATLAS RESOURCES, INC. AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) NOTE 4 - COMMITMENTS AND CONTINGENCIES The Company is the managing general partner in several oil and gas limited partnerships and has agreed to indemnify each investor partner from any liability, which exceeds such partner's share of partnership assets. Management believes that any such liabilities that may occur will be covered by insurance and, if not covered by insurance, will not result in a significant loss to the Company. Subject to certain conditions, investor partners in certain oil and gas limited partnerships have the right to present their interests for purchase by the Company, as managing general partner. The Company will determine the purchase price in accordance with the respective partnership agreement. The Company is not obligated to purchase more than 5% or 10% of the units in any calendar year. Based on past experience, the Company believes that any liability incurred would not be material. The Company may be required to subordinate a part of its net partnership revenues to the receipt by investor partners of cash distributions from the Partnership equal to at least 10% of their agreed subscriptions determined on a cumulative basis, in accordance with the terms of the partnership agreement. The Company is also party to various routine legal proceedings arising out of the ordinary course of its business. Management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on the Company's financial condition or operations. In July 2002, the Company's parent (Atlas), entered into a $75.0 million credit facility led by Wachovia Bank. The revolving credit facility has an initial borrowing base of $45.0 million which may be increased subject to growth in Atlas' oil and gas reserves. The facility permits draws based on the remaining proved developed non-producing and proved undeveloped natural gas and oil reserves attributable to Atlas' wells and the projected fees and revenues from operation of the wells and the administration of partnerships. Up to $10.0 million of the facility may be in the form of standby letters of credit. The facility is secured by Atlas' assets, including those of the Company. The revolving credit facility has a term ending in July 2005 and bears interest at one of two rates (elected at the borrower's option) which increase as the amount outstanding under the facility increases: (i) Wachovia prime rate plus between 25 to 75 basis points, or (ii) LIBOR plus between 175 and 225 basis points. The credit facility contains financial covenants, including covenants requiring Atlas and RAI to maintain specified financial ratios, and imposes the following limits: (a) the amount of debt that can be incurred cannot exceed specified levels without the banks' consent; and (b) the energy affiliates may not sell, lease or transfer property without the banks' consent. This credit facility was used to pay off the previous energy revolving credit facility at PNC Bank. At September 30, 2002, $45.0 million was outstanding under this facility, including $43.7 in outstanding borrowings at interest rates ranging from 3.54% to 5.0% and $1.3 million under letters of credit. The Company owed no amounts due under this facility. 136 ATLAS RESOURCES, INC. AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) NOTE 5 - HEDGING ACTIVITIES The Company enters into natural gas futures and option contracts to hedge its exposure to changes in natural gas prices. At any point in time, such contracts may include regulated New York Mercantile Exchange ("NYMEX") futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the delivery of natural gas. Effective October 1, 2000, the Company adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," (as amended by SFAS 138). This statement establishes accounting and reporting standards for derivative instruments and hedging activities. The statement requires that all derivative financial statements are recognized in the financial statements as either assets or liabilities measured at fair value. Changes in the fair value of derivative financial instruments are recognized in income or other comprehensive income, depending on their classification. Upon adoption of SFAS 133, the Company did not incur any transition adjustments to earnings. The Company formally documents all relationships between hedging instruments and the items being hedged, including the Company's risk management objective and strategy for undertaking the hedging transactions. This includes matching the natural gas futures and options contracts to the forecasted transactions. The Company assesses, both at the inception of the hedge and on an ongoing basis, whether the derivatives are highly effective in offsetting changes in fair value of hedged items. When it is determined that a derivative is not highly effective as a hedge or it has ceased to be a highly effective hedge, due to the loss of correlation between changes in gas reference prices under a hedging instrument and actual gas prices the Company will discontinue hedge accounting for the derivative and further changes in fair value for the derivative will be recognized immediately into earnings. Any gains or losses that were accumulated in other comprehensive income (loss) will be recognized in earnings when the hedged transaction is recognized in earnings. At September 30, 2002, the Company had 267 open natural gas futures contracts related to natural gas sales covering 747,600 dekatherm ("Dth") (net to the Company) maturing through September 2003 at a combined average settlement price of $3.58 per Dth. The fair value of the open natural gas futures contracts, $2,995,100 at September 30, 2002, is based on quoted market prices. As these contracts qualify and have been designated as cash flow hedges, any gains or losses resulting from market price changes are deferred and recognized as a component of sales revenues in the month the gas is sold. Gains or losses on futures contracts are determined as the difference between the contract price and a reference price, generally prices on NYMEX. The Company's net unrealized loss related to open NYMEX contracts was approximately $316,600 at September 30, 2002 and its net unrealized gain was approximately $15,000 at September 30, 2001. The unrealized loss of $218,400 net of taxes of $98,200, at September 30, 2002 has been recorded as a liability in the Company's 2002 Consolidated Financial Statements and in Stockholders' Equity as a component of Other Comprehensive Income (loss). The Company recognized a loss of $59,000 and $599,000 on settled contracts covering natural gas production for the years ended September 30, 2002 and 2001, respectively. As of September 30, 2002, all of the deferred net losses on derivative instruments included in accumulated other comprehensive income (loss) are expected to be reclassified to earnings during the next twelve months. The Company recognized no gains or losses during the fiscal year ended September 30, 2002 for hedge ineffectiveness or as a result of the discontinuance of cash flow hedges. Although hedging provides the Company some protection against falling prices, these activities could also reduce the potential benefits of price increases, depending upon the instrument. NOTE 6 - MAJOR CUSTOMERS During both fiscal 2002 and 2001 one purchaser, First Energy Solutions Corporation, accounted for 17% of total revenues. 137 ATLAS RESOURCES, INC. AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) NOTE 7 - SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) Results of operations for oil and gas producing activities:
Years Ended September 30, ------------------------------- 2002 2001 ------------- ------------- (in thousands) Revenues $ 10,056 $ 10,622 Production costs (1,543) (1,315) Exploration expenses (635) (401) Depreciation, depletion, and amortization (3,949) (2,937) ------------- ------------- Results of operations producing activities $ 3,929 $ 5,969 ============= =============
Capitalized Costs Related to Oil and Gas Producing Activities. The components of capitalized costs related to the Company's oil and gas producing activities are as follows:
Years Ended September 30, -------------------------- 2002 2001 --------- --------- (in thousands) Mineral Interest in Properties: Proved properties........................................ $ 1 $ 161 Unproved properties...................................... 22 125 Wells and related equipment................................. 59,484 44,133 Support equipment........................................... 250 26 --------- ---------- 59,757 44,445 Accumulated depreciation, depletion, amortization and valuation allowances............................... (10,506) (6,456) --------- ---------- Net capitalized costs................................ $ 49,251 $ 37,989 ========= ==========
Costs Incurred in Oil and Gas Producing Activities. The costs incurred by the Company in its oil and gas activities during fiscal years 2002 and 2001 are as follows:
Years Ended September 30, ------------------------------- 2002 2001 -------------- ------------- (in thousands) Property acquisition costs: Unproved properties $ 4 $ 68 Proved properties $ 1 $ - Exploration costs $ 635 $ 401 Development costs $ 19,018 $ 14,766
The development costs above for the years ended September 30, 2002 and 2001 were substantially all incurred for the development of proved undeveloped properties. 138 ATLAS RESOURCES, INC. AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) NOTE 7 - SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) - (Continued) Oil and Gas Reserve Information (Unaudited). The estimates of the Company's proved and unproved gas reserves are based upon evaluations made by management and verified by Wright & Company, Inc., an independent petroleum engineering firm, as of September 30, 2002 and 2001. All reserves are located within the United States. Reserves are estimated in accordance with guidelines established by the Securities and Exchange Commission and the Financial Accounting Standards Board which require that reserve estimates be prepared under existing economic and operating conditions with no provision for price and cost escalation except by contractual arrangements. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e. prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangement, but not on escalations based upon future conditions. o Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation tests. The area of a reservoir considered proved includes (a) that portion delineated by drilling and defined by gas-oil and/ or oil-water contracts, if any; and (b) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir. o Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the "proved" classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based. o Estimates of proved reserves do not include the following: (a) oil that may become available from known reservoirs but is classified separately as "indicated additional reservoirs" (b) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics or economic factors; (c) crude oil, natural gas and natural gas liquids, that may occur in undrilled prospects; and (d) crude oil and natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources. Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operation methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as "proved developed reserves" only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved. There are numerous uncertainties inherent in estimating quantities of proven reserves and in projecting future net revenues and the timing of development expenditures. The reserve data presented represents estimates only and should not be construed as being exact. In addition, the standardized measures of discounted future net cash flows may not represent the fair market value of the Company's oil and gas reserves or the present value of future cash flows of equivalent reserves, due to anticipated future changes in oil and gas prices and in production and development costs and other factors for which effects have not been proved. 139 ATLAS RESOURCES, INC. AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) NOTE 7 - SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) - (Continued) The standardized measure of discounted future net cash flows is information provided for the financial statement user as a common base for comparing oil and gas reserves of enterprises in the industry.
Gas Oil -------------- -------------- (mcf) (bbls) -------------- -------------- Balance September 30, 2000 70,198,510 3,747 Current addition 17,808,029 65,692 Transfers to limited partnerships (11,871,230) -- Revisions (2,054,459) 15,978 Production (2,137,286) (2,885) -------------- -------------- Balance September 30, 2001 71,943,564 82,532 -------------- -------------- Current addition 17,855,966 43,089 Transfers to limited partnerships and Parent's affiliate (7,396,491) (65,692) Revisions (5,321,048) (1,876) Production (2,944,605) (3,505) -------------- -------------- Balance September 30, 2002 74,137,386 54,548 ============== ============== Proved developed reserves at September 30, 2002 36,250,709 23,162 September 30, 2001 34,075,205 16,840
The following schedule presents the standardized measure of estimated discounted future net cash flows relating to proved oil and gas reserves. The estimated future production is priced at year-end prices, adjusted only for fixed and determinable increases in natural gas prices provided by contractual agreements. The resulting estimated future cash inflows are reduced by estimated future costs to develop and produce the proved reserves based on year-end cost levels. The future net cash flows are reduced to present value amounts by applying a 10% discount factor. The standardized measure of future cash flows was prepared using the prevailing economic conditions existing at September 30, 2002 and 2001 and such conditions continually change. Accordingly such information should not serve as a basis in making any judgment on the potential value of recoverable reserves or in estimating future results of operations. 140 ATLAS RESOURCES, INC. AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) NOTE 7 - SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) - (Continued)
Years Ended September 30, ------------------------------- 2002 2001 ------------- ------------- (in thousands) Future cash inflows $ 288,574 $ 288,802 Future production costs (63,697) (52,223) Future development costs (54,060) (50,873) Future income tax expenses (41,694) (45,260) ------------- ------------- Future net cash flows 129,123 140,446 Less 10% annual discount for estimated timing of cash flows (80,521) (87,206) ------------- ------------- Standardized measure of discounted future net cash flows $ 48,602 $ 53,240 ============= =============
The future cash flows estimated to be spent to develop proved undeveloped properties in the years ended September 30, 2003 and 2004 are $27.3 million and $26.8 million, respectively. The following table summarizes the changes in the standardized measure of discounted future net cash flows from estimated production of proved oil and gas reserves after income taxes.
Years Ended September 30, ------------------------------- 2002 2001 ------------- ------------- (in thousands) Balance, beginning of year $ 53,240 $ 45,083 Increase (decrease) in discounted future net cash flows: Sales and transfers of oil and gas, net of related costs (8,513) (9,307) Net changes in prices and production costs (6,038) (7,129) Revisions of previous quantity estimates (5,633) (3,007) Development costs incurred 3,555 4,002 Changes in future development costs (149) (853) Transfers to limited partnerships and Parent's affiliate (4,047) (5,596) Extensions, discoveries, and improved recovery less related costs 11,049 16,982 Accretion of discount 6,653 6,788 Net changes in future income taxes 1,107 9,503 Other (2,622) (3,226) ------------- ------------- Balance, end of year $ 48,602 $ 53,240 ============= =============
141 Consolidated Financial Statements (unaudited) Atlas Resources, Inc. and Subsidiary June 30, 2003 142 ATLAS RESOURCES, INC. AND SUBSIDIARY CONSOLIDATED BALANCE SHEETS JUNE 30, 2003 AND SEPTEMBER 30, 2002 (in thousands, except share data)
June 30, September 30, 2003 2002 ------------ ----------- (Unaudited) (Audited) ASSETS Current assets: Cash and cash equivalents........................................................ $ 9,056 $ 698 Accounts receivable.............................................................. 5,863 5,419 Other current assets............................................................. 327 320 ------------ ----------- Total current assets......................................................... 15,246 6,437 Property and equipment: Oil and gas properties and equipment (successful efforts)........................ 76,357 59,757 Buildings and land............................................................... 2,830 2,830 Other............................................................................ 414 394 ------------ ----------- 79,601 62,981 Less - accumulated depreciation, depletion and amortization......................... (13,423) (10,995) ------------ ----------- Net property and equipment....................................................... 66,178 51,986 Goodwill ...................................................................... 20,868 20,868 Operating and management contracts (less accumulated amortization of $2,311 and $1,953)............................. 4,082 4,400 ------------ ----------- Total assets................................................................. $ 106,374 $ 83,691 ============ =========== LIABILITIES AND STOCKHOLDER'S EQUITY Current liabilities: Accounts payable and accrued liabilities......................................... $ 8,091 $ 3,380 Deferred revenue on drilling contracts........................................... 13,827 4,948 Advances and note from Parent.................................................... 55,824 51,054 ------------ ----------- Total current liabilities.................................................... 77,742 59,382 Long-term debt...................................................................... 208 - Asset retirement obligation......................................................... 3,529 - Commitments and contingencies....................................................... - - Stockholder's equity: Common stock - stated value $10 per share; 500 authorized shares; 200 shares issued and outstanding....................... 2 2 Additional paid-in capital....................................................... 16,505 16,505 Accumulated other comprehensive loss............................................. (247) (212) Retained earnings................................................................ 8,635 8,014 ------------ ----------- Total stockholder's equity................................................. 24,895 24,309 ------------ ----------- $ 106,374 $ 83,691 ============ ===========
See accompanying notes to consolidated financial statements 143 ATLAS RESOURCES, INC. AND SUBSIDIARY CONSOLIDATED STATEMENTS OF INCOME NINE MONTHS ENDED JUNE 30, 2003 AND 2002 (Unaudited) (in thousands)
2003 2002 ------------ ----------- REVENUES Well drilling........................................................................ $ 38,167 $ 36,991 Gas and oil production............................................................... 11,705 5,923 Well services........................................................................ 4,241 5,176 Other................................................................................ 110 131 ------------ ----------- 54,223 48,221 COSTS AND EXPENSES Well drilling......................................................................... 33,188 32,941 Gas and oil production and exploration................................................ 1,276 2,149 Well services......................................................................... 909 1,008 Non-direct............................................................................ 12,749 6,303 Depreciation, depletion and amortization.............................................. 3,670 3,382 Interest.............................................................................. 1,709 1,567 ------------ ----------- Total costs and expenses..................................................... 53,501 47,350 ------------ ----------- Income before income taxes............................................................ 722 871 Provision for income taxes............................................................ 101 215 ------------ ----------- Net income............................................................................ $ 621 $ 656 ============ ===========
ATLAS RESOURCES, INC. AND SUBSIDIARY CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDER'S EQUITY NINE MONTHS ENDED JUNE 30, 2003 (Unaudited) (in thousands, except share data)
Common stock Additional Accumulated Totals ---------------------------- Paid-In Comprehensive Retained Stockholder's Shares Amount Capital Loss Earnings Equity ---------------------------------------------------------------------------------------- Balance, October 1, 2002.................. 200 $ 2 $ 16,505 $ (212) $ 8,014 $ 24,309 Other comprehensive loss.................. (35) (35) Net income................................ 621 621 ------- --------- ---------- --------- -------- ----------- Balance, June 30, 2003.................... 200 $ 2 $ 16,505 $ (247) $ 8,635 $ 24,895 ======= ========= ========== ========= ======== ===========
See accompanying notes to consolidated financial statements 144 ATLAS RESOURCES, INC. AND SUBSIDIARY CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME NINE MONTHS ENDED JUNE 30, 2003 AND 2002 (Unaudited) (in thousands)
2003 2002 ---------- ----------- Net income................................................................. $ 621 $ 656 Unrealized holding losses arising during the period, net of taxes of $364 and $46.............................................. (761) (123) Less reclassification adjustment for losses realized in net income, net of taxes $358........................................................ 726 - ---------- ----------- Comprehensive income....................................................... $ 586 $ 533 ========== ===========
ATLAS RESOURCES, INC. AND SUBSIDIARY CONSOLIDATED STATEMENTS OF CASH FLOWS NINE MONTHS ENDED JUNE 30, 2003 AND 2002 (Unaudited) (in thousands)
2003 2002 ----------- ----------- CASH FLOWS FROM OPERATING ACTIVITIES: Net income.......................................................................... $ 621 $ 656 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization......................................... 3,670 3,382 Gain on asset sale............................................................... (12) License fees and interest on intercompany note due to parent..................... 8,799 9,409 Change in operating assets and liabilities: Increase in accounts receivable and other current assets......................... (962) (11,853) Increase in accounts payable and other current liabilities....................... 11,837 3,090 ----------- ----------- Net cash provided by operating activities........................................... 23,953 4,684 CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures................................................................ (14,086) (17,970) Proceeds-From asset sales........................................................... 12 - ----------- ----------- Net cash used in investing activities............................................... (14,074) (17,970) CASH FLOWS FROM FINANCING ACTIVITIES: Borrowings - long-term debt......................................................... 228 - Payments - long-term debt........................................................... (20) - Advances (to) from Parent and Affiliates............................................ (1,729) 8,878 ----------- ----------- Net cash provided by (used in) financing activities................................. (1,521) 8,878 ----------- ----------- Increase (decrease) in cash and cash equivalents.................................... 8,358 (4,408) Cash and cash equivalents at beginning of year...................................... 698 5,358 ----------- ----------- Cash and cash equivalents at end of year............................................ $ 9,056 $ 950 =========== ===========
See accompanying notes to consolidated financial statements 145 ATLAS RESOURCES, INC. AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS JUNE 30, 2003 (Unaudited) NOTE 1 - INTERIM FINANCIAL STATEMENTS The consolidated financial statements of Atlas Resources, Inc. and its wholly-owned subsidiary (the "company") as of June 30, 2003 and for the nine months ended June 30, 2003 and 2002, are unaudited. These consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("US GAAP") for interim financial information and certain rules and regulations of the Securities and Exchange Commission. Accordingly, they do not include all of the information and footnotes required by US GAAP for complete financial statements. The preparation of financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect (i) the reported amounts of assets and liabilities, (ii) disclosure of contingent assets and liabilities as of the dates of the financial statements and (iii) the reported amounts of revenues and expenses during the reporting periods. In the opinion of management, all adjustments (consisting only of normal recurring adjustments and certain cost allocations for expenses paid by either the Parent or its' affiliates on behalf of the Company) considered necessary for a fair presentation have been reflected in these consolidated financial statements. Operating results for the nine months ended June 30, 2003, are not necessarily indicative of the results that may be expected for the year ending September 30, 2003. Certain reclassifications have been made in the fiscal 2002 consolidated financial statements to conform to the fiscal 2003 presentation. These financial statements should be read in conjunction with the Company's audited September 30, 2002 consolidated financial statements. NOTE 2 - CONSOLIDATED STATEMENTS OF CASH FLOWS Supplemental disclosure of cash flow information: Nine Months Ended June 30, ------------------------- 2003 2002 --------- -------- (in thousands) Cash paid during the period for: Interest..................................... $ 250 $ 264 Income taxes................................. - - NOTE 3 - RECENTLY ISSUED FINANCIAL ACCOUNTING STANDARDS In April 2003, the Financial Accounting Standards Board ("FASB") issued SFAS No. 149 ("SFAS 149") "Amendment of Statement 133 on Derivative Instruments and Hedging Activates." SFAS 149 is effective for contracts entered into or modified after June 30, 2003 and amends and clarifies financial accounting and reporting for derivative instruments. The Company believes that adoption of SFAS 149 will not have a material effect on its financial position or results of operations. In November 2002, the FASB issued Interpretation 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" ("FIN 45"). ). FIN 45 clarifies the requirements of FASB Statement of Financial Accounting Standards No. 5, Accounting for Contingencies ("SFAS 5") relating to a guarantor's accounting for, and disclosure of, the issuance of certain types of guarantees. FIN 45 provides for additional disclosure requirements related to guarantees which were effective for financial periods ending after December 15, 2002. Additionally, FIN 45 outlines provisions for initial recognition and measurement of the liability incurred in providing a guarantee. The Company adopted the initial recognition and measurement requirements for all guarantees as of January 1, 2003. The initial adoption of the recognition and measurement requirements of FIN 45 did not have a significant impact on the results of operations or equity of the Company. 146 ATLAS RESOURCES, INC. AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued JUNE 30, 2003 (Unaudited) NOTE 4 - ASSET RETIREMENT OBLIGATIONS SFAS No. 143, "Accounting for Asset Retirement Obligations" ("SFAS 143"), establishes requirements for the accounting for the removal costs associated with asset retirements. The adoption of SFAS 143 on October 1, 2002 resulted in the recording of an additional cost basis of $1.9 million to oil and gas properties and equipment representing the Company's share of estimated future well plugging and abandonment costs (as discounted to the present value at the dates the wells began operations) for wells in which it has a working interest. In addition, the Company recorded a corresponding retirement obligation liability of $3.4 million (which includes accretion of the discounted present value to September 30, 2002). The cumulative and pro forma effects of initially applying SFAS 143 were not material to the Company's Consolidated Statements of Income. The Company has no assets legally restricted for purposes of settling asset retirement obligations. Except for the item above, the Company has determined that there are no other material retirement obligations associated with tangible long-lived assets. A reconciliation of the Company's liability for well plugging and abandonment costs for the nine months ended June 30, 2003 is as follows (in thousands): Asset retirement obligations, September 30, 2002................... $ - Adoption of SFAS 143............................................... 3,380 Accretion expense.................................................. 149 --------- Asset retirement obligations, June 30, 2003........................ $ 3,529 ========= The above accretion expense is included in depreciation, depletion and amortization in the Company's consolidated statements of income. NOTE 5 - COMMITMENTS AND CONTINGENCIES The Company is the managing general partner in several oil and gas limited partnerships and has agreed to indemnify each investor partner from any liability, which exceeds such partner's share of partnership assets. Management believes that any such liabilities that may occur will be covered by insurance and, if not covered by insurance, will not result in a significant loss to the Company. Subject to certain conditions, investor partners in certain oil and gas limited partnerships have the right to present their interests for purchase by the Company, as managing general partner. The Company will determine the purchase price in accordance with the respective partnership agreement. The Company is not obligated to purchase more than 5% or 10% of the units in any calendar year. Based on past experience, the Company believes that any liability incurred would not be material. The Company may be required to subordinate a part of its net partnership revenues to the receipt by investor partners of cash distributions from the Partnership equal to at least 10% of their agreed subscriptions determined on a cumulative basis, in accordance with the terms of the partnership agreement. The Company is also party to various routine legal proceedings arising out of the ordinary course of its business. Management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on the Company's financial condition or operations. 147 ATLAS RESOURCES, INC. AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued JUNE 30, 2003 (Unaudited) NOTE 5 - COMMITMENTS AND CONTINGENCIES (CONTINUED) In July 2002, the Company's parent (Atlas), entered into a $75.0 million credit facility led by Wachovia Bank. The revolving credit facility has a borrowing base of $52.5 million at June 30, 2003 and may be increased subject to growth in Atlas' oil and gas reserves. The facility permits draws based on the remaining proved developed non-producing and proved undeveloped natural gas and oil reserves attributable to Atlas' energy subsidiaries' wells and the projected fees and revenues from operation of the wells and the administration of partnerships. At June 30, 2003, $30 million was outstanding under this facility; the Company owed no amounts due under this facility. NOTE 6 - DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES The Company enters into natural gas futures and option contracts to hedge its exposure to changes in natural gas prices. At any point in time, such contracts may include regulated New York Mercantile Exchange ("NYMEX") futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the delivery of natural gas. The Company formally documents all relationships between hedging instruments and the items being hedged, including the Company's risk management objectives and strategy for undertaking the hedging transactions. This includes matching the natural gas futures and options contracts to the hedged asset. The Company assesses, both at the inception of the hedge and on an ongoing basis, whether the derivatives are highly effective in offsetting changes in fair value of hedged items. When it is determined that a derivative is not highly effective as a hedge or it has ceased to be a highly effective hedge due to the loss of correlation between changes in gas reference prices under a hedging instrument and actual gas prices, the Company will discontinue hedge accounting for the derivative and further changes in fair value for the derivative will be recognized immediately into earnings. Gains or losses on these instruments are accumulated in other comprehensive income (loss) to the extent that these hedges are deemed to be highly effective as hedges, and are recognized in earnings in the period in which the hedged item is recognized in earnings. At June 30, 2003, the Company had 67 open natural gas futures contracts related to natural gas sales covering 201,000 dekatherms ("Dth") (net to the Company) of natural gas, maturing through September 2003 at a combined average settlement price of $3.63 per Dth. Based on quoted market prices, the fair value of the Company's open natural gas futures contracts at June 30, 2003, is $1.1 million. As these contracts qualify and have been designated as cash flow hedges, any gains or losses resulting from market price changes are deferred and recognized as a component of sales revenues in the month the gas is sold, unless the hedges are no longer "highly effective." Gains or losses on futures contracts are determined as the difference between the contract price and a reference price, generally prices on NYMEX. The Company's net unrealized loss related to open NYMEX contracts was approximately $363,000 at June 30, 2003 and $317,000 at September 30, 2002. The unrealized losses, net of applicable taxes, have been recorded as a liability in the Company's Consolidated Balance Sheets and in Stockholders' Equity as a component of Accumulated Other Comprehensive Income. The Company recognized losses of $1.1 million on settled contracts for the nine months ended June 30, 2003. The Company recognized no gains or losses during the nine months ended June 30, 2003 for hedge ineffectiveness or as a result of the discontinuance of cash flow hedges. As of June 30, 2003, all of the deferred net losses on derivative instruments included in accumulated other comprehensive income (loss) are expected to be reclassified to earnings during the next three months. Although hedging provides the Company some protection against falling prices, these activities could also reduce the potential benefits of price increases, depending upon the instrument. NOTE 7- EFFECTIVE TAX RATE The Company's effective tax rate is lower compared to the statutory rate due to the benefit of percentage depletion and certain tax credits. 148 ATLAS RESOURCES, INC. AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued JUNE 30, 2003 (Unaudited) NOTE 8- INTANGIBLE ASSETS In connection with a review of the Company's Parent financial statements by the staff of the Securities and Exchange Commission, the Company has been made aware that an issue has arisen within the industry regarding the application of provisions of SFAS No. 142 and SFAS No. 141, "Business Combinations," to companies in the extractive industries, including gas and oil companies. The issue is whether SFAS No. 142 requires registrants to reclassify costs associated with mineral rights, including both proved and unproved leasehold acquisition costs, as intangible assets in the balance sheet, apart from other capitalized gas and oil property costs. Historically, the Company and other gas and oil companies have included the cost of these gas and oil leasehold interests as part of gas and oil properties. Also under consideration is whether SFAS No. 142 requires registrants to provide the additional disclosures prescribed by SFAS No. 142 for intangible assets for costs associated with mineral rights. If it is ultimately determined that SFAS No. 142 requires the Company to reclassify costs associated with mineral rights from property and equipment to intangible assets, the amounts that would be immaterial to the Company's financial position. The reclassification of these amounts would not effect the method in which such costs are amortized or the manner in which the Company assesses impairment of capitalized costs. As a result, net income would not be affected by the reclassification. 149 APPENDIX A INFORMATION REGARDING CURRENTLY PROPOSED PROSPECTS FOR ATLAS AMERICA PUBLIC #12-2003 LIMITED PARTNERSHIP INFORMATION REGARDING CURRENTLY PROPOSED PROSPECTS The partnerships do not currently hold any interests in any prospects on which the wells will be drilled, and the managing general partner has absolute discretion in determining which prospects will be acquired to be drilled. However, set forth below is information relating to approximately 75 proposed prospects and the wells which will be drilled on the prospects by Atlas America Public #12-2003 Limited Partnership, which is the first partnership in the program and must be closed by December 31, 2003. It is referred to in this section as the "2003 Partnership." One well will be drilled on each prospect, and for purposes of this section the well and prospect are referred to together as the "well." Although the managing general partner does not anticipate that the wells will be selected in the order in which they are set forth below, these wells are currently proposed to be drilled by the 2003 Partnership when the subscription proceeds are released from escrow and from time to time thereafter subject to the managing general partner's right to: o withdraw the wells and to substitute other wells; o take a lesser working interest in the wells; o add other wells; or o any combination of the foregoing. The specified wells represent the necessary wells if approximately $15 million is raised and the 2003 Partnership takes the working interest in the wells which is set forth below in the "Lease Information" for each well. The managing general partner has not proposed any other wells if: o a greater amount of subscription proceeds is raised; o a lesser working interest in the wells is acquired; or o the wells are substituted for any of the reasons set forth below. The managing general partner has not authorized any person to make any representations to you concerning the possible inclusion of any other wells which will be drilled by the 2003 Partnership or any of the other partnerships, and you should rely only on the information in this prospectus. The currently proposed wells will be assigned unless there are circumstances which, in the managing general partner's opinion, lessen the relative suitability of the wells. These considerations include: o the amount of the subscription proceeds received in the 2003 Partnership; o the latest geological and production data available; o potential title or spacing problems; o availability and price of drilling services, tubular goods and services; o approvals by federal and state departments or agencies; o agreements with other working interest owners in the wells; o farmins; and o continuing review of other properties which may be available. 1 Any substituted and/or additional wells will meet the same general criteria for development potential as the currently proposed wells and will generally be located in areas where the managing general partner or its affiliates have previously conducted drilling operations. You, however, will not have the opportunity to evaluate for yourself the relevant production and geological information for the substituted and/or additional wells. The purpose of the information regarding the currently proposed wells is to help you evaluate the economic potential and risks of drilling the proposed wells. This includes production information for wells in the general area of the proposed well which the managing general partner believes is an important indicator in evaluating the economic potential of any well to be drilled. However, a well drilled by the 2003 Partnership may not experience production comparable to the production experienced by wells in the surrounding area since the geological conditions in these areas can change in a short distance. Also, the managing general partner has not been able to obtain production information for previously drilled wells in the immediate areas where a portion of the currently proposed wells in Pennsylvania are situated because the information is not available to the managing general partner as discussed in "Risk Factors - Risks Related to an Investment In a Partnership - Lack of Production Information Increases Your Risk and Decreases Your Ability to Evaluate the Feasibility of a Partnership's Drilling Program." These wells, for which no production data for other wells in the immediate area are available to the managing general partner, have been proposed by the managing general partner to be drilled based on geologic trends in the immediate area where production has been established, such as sand thickness, porosities and water saturations, which lead the managing general partner to believe that the proposed wells will have similar production. When reviewing production information for each well offsetting or in the general area of a proposed well to be drilled you should consider the factors set forth below. o The length of time that the well has been on-line, and the period for which production information is shown. Generally, the shorter the period for which production information is shown the less reliable the production information. o Production from a well declines throughout the life of the well, but the rate of decline (the "decline curve") may be affected by the operation of the well and the geological location of the well. o The greatest volume of production from a well ("flush production") usually occurs in the early period of well operations and may indicate a greater reserve volume than the well actually will produce. This period of flush production can vary depending on how the well is operated and the location of the well. o The production information for some wells is incomplete or very limited. The designation "N/A" means: o the production information was not available to the managing general partner for the reasons discussed in "Risk Factors - Risks Related to an Investment In a Partnership - Lack of Production Information Increases Your Risk and Decreases Your Ability to Evaluate the Feasibility of a Partnership's Drilling Program."; or o if the managing general partner was the operator, then when the information was prepared the well was either: o not completed; o not on-line to sell production; or o producing for only a short period of time. o Production information for wells located close to a proposed well tends to be more relevant than production information for wells located farther away, although even with wells located close together well performance and the volume of production from the wells can be much different. 2 o Consistency in production among wells tends to confirm the reliability and predictability of the production. To help you become familiar with the proposed wells the information set forth below is included.
o A map of western Pennsylvania and eastern Ohio showing their counties. ......................................... 4 o Western Pennsylvania (Clinton/Medina Geological Formation) o Lease information for western Pennsylvania and eastern Ohio. ............................................. 6 o Location and Production Map for western Pennsylvania and eastern Ohio showing the proposed wells and the wells in the area. ................................................................................. 9 o Production data for western Pennsylvania and eastern Ohio. ............................................... 11 o United Energy Development Consultants, Inc.'s geologic evaluation for western Pennsylvania and eastern Ohio. .................................................................................................. 15 o Fayette County, Pennsylvania (Mississippian/Upper Devonian Sandstone Reservoirs) o Lease information for Fayette and Greene Counties, Pennsylvania. ......................................... 21 o Location and Production Maps for Fayette and Greene Counties, Pennsylvania showing the proposed wells and the wells in the area. ............................................................................. 23 o Production data for Fayette and Greene Counties, Pennsylvania. ........................................... 29 o United Energy Development Consultants, Inc.'s geologic evaluation for Fayette and Greene Counties, Pennsylvania. .......................................................................................... 39 o Armstrong County, Pennsylvania (Upper Devonian Sandstone Reservoirs) o Lease information for Armstrong and Indiana Counties, Pennsylvania. ...................................... 45 o Location and Production Map for Armstrong and Indiana Counties, Pennsylvania showing the proposed wells and the wells in the area. ....................................................................... 47 o Production data for Armstrong and Indiana Counties, Pennsylvania ......................................... 49 o United Energy Development Consultants, Inc.'s geologic evaluation for Armstrong and Indiana Counties, Pennsylvania. .......................................................................................... 54
3 MAP OF WESTERN PENNSYLVANIA AND EASTERN OHIO 4 [GRAPHIC OMITTED] 5 LEASE INFORMATION FOR WESTERN PENNSYLVANIA AND EASTERN OHIO 6
Overriding Royalty Interest to Overriding Net Effective Expiration Landowner the Managing Royalty Interest Revenue Prospect Name County Date* Date* Royalty General Partner to 3rd Parties Interest ---------------------------------------------------------------------------------------------------------------------------------- 1. Horne #3 Crawford 11/14/01 HBP 12.5% 0% 0% 87.5% 2. Bazylak #3 Crawford 10/24/01 HBP 12.5% 0% 0% 87.5% 3. Biemer Unit #2 Crawford 02/05/02 HBP 12.5% 0% 0% 87.5% 4. Dygert #1 Crawford 03/27/02 03/27/05 12.5% 0% 0% 87.5% 5. Stritzinger #2 Crawford 12/16/02 12/16/04 12.5% 0% 0% 87.5% 6. Nelson #9 Crawford 04/10/02 04/10/05 12.5% 0% 0% 87.5% 7. Shuffstall #2 Crawford 02/28/02 02/28/05 12.5% 0% 0% 87.5% 8. Ballut #1 Crawford 06/21/02 06/21/05 12.5% 0% 0% 87.5% 9. Warren #3 Crawford 02/02/02 02/02/05 12.5% 0% 0% 87.5% 10. Warren #4 Unit Crawford 02/02/02 02/02/05 12.5% 0% 0% 87.5% 11. Warren #5 Crawford 02/28/02 02/28/05 12.5% 0% 0% 87.5% 12. Grudoski #1 Crawford 11/16/02 11/16/05 12.5% 0% 0% 87.5% 13. Byler #96 Crawford 08/19/02 08/19/05 12.5% 0% 0% 87.5% 14. Fisher #4 Crawford 05/02/02 05/02/05 12.5% 0% 0% 87.5% 15. Townsend #4 Crawford 08/19/02 08/19/05 12.5% 0% 0% 87.5% 16. Byler #103 Crawford 11/11/02 11/11/05 12.5% 0% 0% 87.5% 17. Detweiler #6 Crawford 04/22/02 04/22/05 12.5% 0% 0% 87.5% 18. Detweiler #7 Crawford 04/22/02 04/22/05 12.5% 0% 0% 87.5% 19. Shrock #2 Crawford 06/12/02 06/12/05 12.5% 0% 0% 87.5% 20. Mullenax #1 Crawford 02/24/03 02/24/06 12.5% 0% 0% 87.5% 21. Klein #3 Crawford 02/22/03 02/22/06 12.5% 0% 0% 87.5% 22. Byler #104 Crawford 03/14/02 03/14/05 12.5% 0% 0% 87.5% 23. Przepiora #1 Crawford 03/17/03 03/17/06 12.5% 0% 0% 87.5% 24. Seeley #1 Crawford 08/05/02 08/05/05 12.5% 0% 0% 87.5% 25. Riley #3 Crawford 07/01/02 07/01/05 12.5% 0% 0% 87.5% 26. Collins #2 Crawford 07/01/02 07/01/05 12.5% 0% 0% 87.5% 27. Adsit #1 Crawford 07/24/02 07/24/05 12.5% 0% 0% 87.5% 28. Adsit #2 Crawford 07/24/02 07/24/05 12.5% 0% 0% 87.5% Acres to be Working Net Assigned to the Prospect Name Interest Acres Partnership ----------------------------------------------------------------- 1. Horne #3 100% 145 50 2. Bazylak #3 100% 200 50 3. Biemer Unit #2 100% 117 50 4. Dygert #1 100% 115 50 5. Stritzinger #2 100% 201 50 6. Nelson #9 100% 250 50 7. Shuffstall #2 100% 110 50 8. Ballut #1 100% 19 19 9. Warren #3 100% 100 50 10. Warren #4 Unit 100% 100 50 11. Warren #5 100% 98 50 12. Grudoski #1 100% 47 47 13. Byler #96 100% 52 50 14. Fisher #4 100% 92 50 15. Townsend #4 100% 125 50 16. Byler #103 100% 91 50 17. Detweiler #6 100% 120 50 18. Detweiler #7 100% 120 50 19. Shrock #2 100% 70 50 20. Mullenax #1 100% 73 50 21. Klein #3 100% 53 50 22. Byler #104 100% 20 20 23. Przepiora #1 100% 57 50 24. Seeley #1 100% 65 50 25. Riley #3 100% 67 50 26. Collins #2 100% 74 50 27. Adsit #1 100% 100 50 28. Adsit #2 100% 100 50
7
Overriding Royalty Interest to Overriding Net Effective Expiration Landowner the Managing Royalty Interest Revenue Prospect Name County Date* Date* Royalty General Partner to 3rd Parties Interest ---------------------------------------------------------------------------------------------------------------------------------- 29. Merlin Enterprises #1 Crawford 07/08/02 07/08/05 12.5% 0% 0% 87.5% 30. Merlin Enterprises #2 Crawford 07/08/02 07/08/05 12.5% 0% 0% 87.5% 31. Merlin Enterprises #3 Crawford 07/08/02 07/08/05 12.5% 0% 0% 87.5% 32. Feidler #1 Crawford 04/11/03 04/11/06 12.5% 0% 0% 87.5% Acres to be Working Net Assigned to the Prospect Name Interest Acres Partnership ----------------------------------------------------------------- 29. Merlin Enterprises #1 100% 327 50 30. Merlin Enterprises #2 100% 327 50 31. Merlin Enterprises #3 100% 327 50 32. Feidler #1 100% 43 43
- --------------- * HBP - Held by Production. 8 LOCATION AND PRODUCTION MAP FOR WESTERN PENNSYLVANIA AND EASTERN OHIO 9 [GRAPHIC OMITTED] 10 PRODUCTION DATA FOR WESTERN PENNSYLVANIA AND EASTERN OHIO 11 The Production Data provided in the table below is not intended to imply that the wells to be drilled by the partnership will have the same results, although it is an importan indicator in evaluating the economic potential of any well to be drilled by the partnership.
TOTAL MCF THROUGH TOTAL LATEST ID DATE MOS 06/30/03 EXCEPT LOGGERS 30 DAY NUMBER OPERATOR WELL NAME COMPLT'D ON LINE WHERE NOTED DEPTH PROD. 1. 20483 N-REN Corp. Kebert Developers #2 09/21/75 N/A N/A 4901 N/A 2. 20519 R. D. Werner & Company Lashinsky, E. #1 05/27/83 N/A N/A 4672 N/A 3. 20613 R. D. Werner & Company Horne, D. #1 05/31/84 N/A N/A 4659 N/A 4. 20616 Pominex, Inc. Williams #1 11/16/85 N/A N/A 4980 N/A 5. 20709 R. D. Werner & Company Weaver, M. #1 07/16/85 N/A N/A 4820 N/A 6. 20807 R. D. Werner & Company Johnson, A. #1 06/04/86 N/A N/A 4865 N/A 7. 20809 R. D. Werner & Company Walker, R. #1 06/11/86 N/A N/A 4925 N/A 8. 21209 Cabot Oil & Gas Dygert, Paul #1 07/28/81 N/A N/A 4794 N/A 9. 21212 Cabot Oil & Gas Troyer, Eli #1 08/05/81 N/A Plugged & Abandoned 4641 N/A 10. 21765 Great Lakes Energy Partners Allen, James R. #1 08/09/82 N/A N/A 4545 N/A 11. 22610 Northern Appalachian Foulk #2 11/14/85 N/A N/A 5050 N/A 12. 22611 Northern Appalachian Foulk #3 11/03/85 N/A N/A 5000 N/A 13. 22628 Northern Appalachian Jolley #1 11/25/85 N/A N/A 4930 N/A 14. 22635 Northern Appalachian Foulk #1 11/24/85 N/A N/A 5059 N/A 15. 23776 Atlas Resources, Inc. Seamon #4 08/09/01 17 25685 5129 1274 16. 23792 Atlas Resources, Inc. Williams #11 05/05/02 11 26115 5075 4230 17. 23794 Atlas Resources, Inc. Byler #88 12/08/01 16 34507 5146 2220 18. 23798 Atlas Resources, Inc. Williams #12 12/13/01 16 35305 5097 2312 19. 23816 Atlas Resources, Inc. Williams #14 01/11/02 13 36488 5149 5535 20. 23839 Atlas Resources, Inc. Wotherspoon #2 05/17/02 11 22416 5065 3161 21. 23842 Atlas Resources, Inc. Pallack #9 05/10/02 11 21419 5061 2571 22. 23845 Atlas Resources, Inc. Byler #91 05/08/02 7 14671 5028 2779 23. 23966 Atlas Resources, Inc. McArdle #5 05/27/02 7 12740 5025 2460 24. 23976 Atlas Resources, Inc. Ruhlman #1 06/21/02 7 13629 5069 3424 25. 23977 Atlas Resources, Inc. Jackson #1 07/11/02 3 4207 4978 1807 26. 23982 Atlas Resources, Inc. Bazylak #1 07/03/02 6 9633 5003 2082
12 The Production Data provided in the table below is not intended to imply that the wells to be drilled by the partnership will have the same results, although it is an importan indicator in evaluating the economic potential of any well to be drilled by the partnership.
TOTAL MCF THROUGH TOTAL LATEST ID DATE MOS 06/30/03 EXCEPT LOGGERS 30 DAY NUMBER OPERATOR WELL NAME COMPLT'D ON LINE WHERE NOTED DEPTH PROD. 27. 23984 Atlas Resources, Inc. Jackson #2 08/19/02 2 2533 4973 1432 28. 23985 Atlas Resources, Inc. McArdle #6 09/02/02 3 7040 5008 3474 29. 23991 Atlas Resources, Inc. Jackson #3 08/13/02 2 4863 5003 2417 30. 23998 Atlas Resources, Inc. Saylor #2 08/25/02 N/A N/A 5002 N/A 31. 23999 Atlas Resources, Inc. Bazylak #2 09/01/02 2 2585 5003 2074 32. 24000 Atlas Resources, Inc. Coulter #5 09/13/02 3 2735 5070 1380 33. 24003 Atlas Resources, Inc. Hall #12 09/06/02 2 4691 4967 2206 34. 24006 Atlas Resources, Inc. Horne #1 09/13/02 2 3028 5003 1991 35. 24009 Atlas Resources, Inc. Horne #2 11/04/02 2 2906 5018 1911 36. 24011 Atlas Resources, Inc. McArdle #7 02/18/03 2 1905 5014 1858 37. 24015 Atlas Resources, Inc. Byler #92 10/07/02 2 2363 4972 1698 38. 24021 Atlas Resources, Inc. Horne #5 02/04/03 2 2478 4982 1729 39. 24023 Atlas Resources, Inc. Sperry Farms #1 12/17/02 2 208 4951 96 40. 24026 Atlas Resources, Inc. Sperry Farms #3 12/23/02 3 22 4919 0 41. 24028 Atlas Resources, Inc. Horne #6 12/10/02 3 4661 4984 2634 42. 24029 Atlas Resources, Inc. Lee Unit #4 12/28/02 N/A N/A 5133 N/A 43. 24030 Atlas Resources, Inc. Byler #94 01/14/03 N/A N/A 4932 N/A 44. 24031 Atlas Resources, Inc. Courtney #8 02/12/03 2 3052 5012 1977 45. 24033 Atlas Resources, Inc. Stoker #4 01/07/03 1 775 4989 775 46. 24034 Atlas Resources, Inc. Yoder #12 01/05/03 1 10 4890 10 47. 24035 Atlas Resources, Inc. Horne #7 01/22/03 2 1525 4952 1097 48. 24036 Atlas Resources, Inc. Kiskadden #3 02/05/03 N/A N/A 4884 N/A 49. 24041 Atlas Resources, Inc. Yoder Unit #11 01/11/03 N/A N/A 4923 N/A 50. 24046 Atlas Resources, Inc. Yoder #14 02/02/03 2 1079 4952 638 51. 24047 Atlas Resources, Inc. Horne #8 01/29/03 3 3014 5952 1651 52. 24049 Atlas Resources, Inc. Morian #1 03/07/03 N/A N/A 4917 N/A
13 The Production Data provided in the table below is not intended to imply that the wells to be drilled by the partnership will have the same results, although it is an importan indicator in evaluating the economic potential of any well to be drilled by the partnership.
TOTAL MCF THROUGH TOTAL LATEST ID DATE MOS 06/30/03 EXCEPT LOGGERS 30 DAY NUMBER OPERATOR WELL NAME COMPLT'D ON LINE WHERE NOTED DEPTH PROD. 53. 24055 Atlas Resources, Inc. Kisdadden #1 02/13/03 N/A N/A 4920 N/A 54. 24057 Atlas Resources, Inc. Miller #19 01/27/03 N/A N/A 5062 N/A 55. 24061 Atlas Resources, Inc. Jackson #4 02/24/03 N/A N/A 4982 N/A 56. 24066 Atlas Resources, Inc. Yoder #15 02/07/03 2 477 4920 355 57. 24076 Atlas Resources, Inc. Sperry Farms #2 02/26/03 N/A N/A 4924 N/A 58. 24079 Atlas Resources, Inc. Jacobs #1 03/09/03 N/A N/A 5040 N/A 59. 24080 Atlas Resources, Inc. Sperry Farms #4 02/19/03 2 306 4854 198 60. 24083 Atlas Resources, Inc. Miller #18 03/03/03 N/A N/A 5105 N/A 61. 24097 Atlas Resources, Inc. Biemer #1 03/15/03 N/A N/A 4913 N/A 62. 24101 Atlas Resources, Inc. Sperry Farms Unit #5 03/14/03 N/A N/A 4863 N/A 63. 24102 Atlas Resources, Inc. Herbert #1 03/20/03 N/A N/A 4889 N/A 64. 24105 Atlas Resources, Inc. Miller Unit #20 03/22/03 N/A N/A 4945 N/A 65. 24109 Atlas Resources, Inc. McEntire #1 03/22/03 N/A N/A 4856 N/A 66. 24110 Atlas Resources, Inc. Morrow #2 03/26/03 N/A N/A 4769 N/A 67. 24112 Atlas Resources, Inc. Orr #2 03/29/03 N/A N/A 4855 N/A 68. 24118 Atlas Resources, Inc. Palermo #1 04/02/03 N/A N/A 4887 N/A 69. 90006 Sylvania Corp. Calvin Ellen #2 12/05/43 N/A N/A 4644 N/A 70. 90025 Sylvania Corp. Calvin Ellen #1 05/07/48 N/A Plugged & Abandoned 4896 N/A 71. 00194 Darwin C. Williams Dot #1 N/A N/A N/A N/A N/A 72. 00195 Darwin C. Williams Dot #2 N/A N/A N/A N/A N/A
14 UEDC'S GEOLOGIC EVALUATION FOR THE CURRENTLY PROPOSED WELLS IN WESTERN PENNSYLVANIA AND EASTERN OHIO 15 GEOLOGIC EVALUATION ATLAS AMERICA PUBLIC #12-2003 LIMITED PARTNERSHIP Crawford Prospect Area Pennsylvania Dated: May 6, 2003
Program proposed by: Report submitted by: ATLAS RESOURCES, INC. UEDC 311 Rouser Road United Energy Development Consultants, Inc. P.O. Box 611 1715 Crafton Blvd. Moon Township, PA 15108 Pittsburgh, PA 15205
LOCATION MAP - AREA OF INTEREST [GRAPHIC OMITTED] TABLE OF CONTENTS
INVESTIGATION SUMMARY .................................................... 2 OBJECTIVE ............................................................... 2 AREA OF INVESTIGATION ................................................... 2 METHODOLOGY ............................................................. 2 PROSPECT AREA HISTORY .................................................... 2 DRILLING ACTIVITY ....................................................... 2 GEOLOGY ................................................................. 2 STRATIGRAPHY, LITHOLOGY & DEPOSITION ................................... 2 RESERVOIR CHARACTERISTICS .............................................. 3 PRODUCTION .............................................................. 4 CONCLUSION .............................................................. 5 DISCLAIMER .............................................................. 5 NON-INTEREST ............................................................ 5
16 INVESTIGATION SUMMARY OBJECTIVE The purpose of the following investigation is to evaluate the geologic feasibility and further development of the Crawford Prospect Area as proposed by Atlas Resources, Inc. ("Atlas"). AREA OF INVESTIGATION A portion of this prospect area, herein identified for drilling in Atlas America Public #12-2003 Limited Partnership, contains acreage in East Fallowfield, Greenwood and Sadsbury Townships in Crawford County, Pennsylvania. Thirty-two (32) drilling prospects will be designated for this program and will be targeted to produce natural gas from Clinton-Medina Group reservoirs, found at an average depth range of approximately 5,000 to 6,300 feet beneath the earth's surface over the prospect area. These will be the only prospects evaluated for the purposes of this report. METHODOLOGY The data incorporated into this report was provided by Atlas and the in- house archives of UEDC, Inc. Geological mapping and the interpretations by Atlas geologists were also examined. Available "electric" log, completion, and production data on "key" wells within and adjacent to the defined prospect area were utilized to determine productive and depositional trends. PROSPECT AREA HISTORY DRILLING ACTIVITY The proposed drilling area lies within a region of northwestern Pennsylvania which has been very active for the past decade in terms of exploration for, and exploitation of natural gas reserves. Development within and adjacent to the Crawford Prospect Area has escalated since 1986, with Atlas and it's affiliates drilling over thirteen hundred (1300) wells during this period. Atlas has encountered favorable drilling and production results while solidifying a strong acreage position, and continues to identify and extend productive trends. Drilling is ongoing as of the date of this report with recent wells displaying favorable initial drilling and completion results. Competitive activity has begun east of the prospect area, confirming the Clinton-Medina Group of Lower Silurian age as a viable target for the further development of producible quantities of natural gas. GEOLOGY STRATIGRAPHY, LITHOLOGY & DEPOSITION Regionally, the Clinton-Medina Group was deposited in tide-dominated shoreline, deltaic, and shelf environments and is lithologically comprised of alternating sandstones, siltstones and shales. Productive sandstones are composed of siliceous to dolomitic subarkoses, sublitharenites, and quartz arenites. Reservoir quality sands occur throughout the delta-complex from eastern Ohio through northwestern Pennsylvania and western New York. The Clinton-Medina Group, deposited during the Lower Silurian, overlies the Upper Ordovician age Queenston shale and is capped by the Middle Silurian Reynales Formation. This dolomitic limestone "cap" is known locally to drillers as the "Packer Shell". Stratigraphically, in descending order, the potentially productive units of the Clinton-Medina Group consist of the: 1) Thorold, 2) Grimsby, 3) Cabot Head, 4) Whirlpool members. The diagram illustrates these stratigraphic relationships. [GRAPHIC OMITTED] 17 The Whirlpool is a light gray quartzose sandstone to siltstone ranging in thickness from five (5) to twenty (20) feet. Average porosity values for this sand member range from five (5) to ten (10) percent regionally. Within the area of investigation, porosities in excess of twelve (12) percent occur within localized trends targeted for further development. The Cabot Head is a dark green to black shale, most likely of marine origin. Within the investigated area the Cabot Head sandstone has been encountered in numerous wells. This formation has been found to contribute natural gas when reservoir characteristics, including evidence of enhanced permeability, warrant completion. This sand member is considered a secondary target. The Grimsby is the thickest sandstone member of the Clinton-Medina Group. Sand development ranges from ten (10) to forty-five (45) feet within an interval comprised of fine to very fine, light gray to red sandstones and siltstones broken up by thin dark gray silty shale layers. Average porosity values for the Grimsby are approximately six (6) to (10) percent over the pay interval regionally. Permeability may be enhanced locally by the presence of naturally occurring micro-fractures. Future development focuses on established production trends. The Thorold sandstone is the uppermost producing interval of the Clinton- Medina sequence. This interbedded ferric sand, silt and shale interval averages forty (40) to seventy (70) feet, from west to east in the prospect area. Where pay sand development occurs, porosities are in the typical Clinton-Medina group range of six (6) to (10) percent. Permeability may be enhanced locally by the presence of naturally occurring micro-fractures. RESERVOIR CHARACTERISTICS Petroleum reservoirs are formed by the presence of an impermeable barrier trapping natural gas of commercial quantities in a more permeable medium. In the Clinton-Medina, this occurs either stratigraphically when a permeable sand containing hydrocarbons encounters an impermeable shale or when a permeable sand changes gradually into a non-permeable sand by a cementation process known as "diagenesis". Thus, this type of trap represents cemented-in hydrocarbon accumulations. Electric well logs can be used in conjunction with production to interpret reservoir parameters. When sandstones in the Thorold, Grimsby, Cabot Head or Whirlpool develop porosity in excess of 6%, or a bulk density of 2.55 or less, the permeability of the reservoir (which ranges from <0.l to >40.2 mD) can become great enough to allow commercial production of natural gas. Small, naturally occurring cracks in the formation, referred to as micro-fractures, can also enhance permeability. A gamma, bulk density, density porosity and neutron log suite showing sand development in the Grimsby, Cabot Head and Whirlpool is illustrated. Two other phenomena detected by well logs can occur which are indicators of enhanced permeability. These indicators used to detect productive intervals are: o Mudcake buildup across the zone of interest - after loading the wellbore with brine fluid and circulating, an interval with enhanced permeability will accept fluid, filtering out the solids and leaving behind a buildup (or mudcake) on the formation wall. This is detectable with a caliper log. [GRAPHIC OMITTED] o Invasion profile - during circulation, a brine that has a high conductivity (or low resistivity) that is accepted into the formation (as described above) will change the electrical conductivity of the reservoir rock near and around the wellbore. The resistivity will be low nearest to the wellbore and will increase away from the wellbore. A dual laterolog can be used to detect this profile created by a permeable zone - it records resistivity near the wellbore as well as deeper into the formation. A zone with enhanced permeability will show a separation between the shallow and deep laterologs, while a zone with little or no permeability would cause the two resistivity measurements to read exactly the same. An example follows: 18 GAMMA RAY LOG RESISTIVITY LOG [GRAPHIC OMITTED] PRODUCTION A model decline curve has been created based on the production histories from approximately 900 wells drilled by Atlas and its programs in the adjacent Mercer Fields. This model decline curve is consistent with the average estimated decline curves for over 200 undeveloped well locations in the Mercer Field which were used by Wright & Company, Inc., independent petroleum consultants, in preparing Atlas' year 2000 reserve report. The model decline curve is illustrated in the diagram below: [GRAPHIC OMITTED] It is important to note that the model decline curve is intended only to present how a well's production may decline from year to year, and does not attempt to predict the average recoverable reserves per well. Also, the model decline curve is a forward-looking statement based on certain assumptions and analyses of historical trends, current conditions and expected future developments. The model decline curve is subject to a number of risks and uncertainties including the risk that the wells are productive but do not produce enough revenue to return the investment made and uncertainties concerning the price of natural gas and oil. Actual results in this drilling program will vary from the model decline curve, although a rapid decline in production within the first several years can be expected. 19 STATEMENTS CONCLUSION UEDC has conducted a geologic feasibility study of the drilling area for Atlas America Public #12-2003 Limited Partnership, which will consist of developmental drilling of the Clinton-Medina Group sands primarily in Crawford County, Pennsylvania. It is the professional opinion of UEDC that the drilling of the thirty-two (32) wells by Atlas America Public #12-2003 Limited Partnership is supported by sufficient geologic and engineering data. DISCLAIMER For the purpose of this evaluation, UEDC did not visit any leaseholds or inspect any of the associated production equipment. Likewise, UEDC has no knowledge as to the validity of title, liabilities, or corporate matters affecting these properties. UEDC does not warrant individual well performance. NON-INTEREST We hereby confirm that UEDC is an independent consulting firm and that neither this firm or any of it's employees, contract consultants, or officers has, or is committed to acquire any interest, directly or indirectly, in Atlas Resources, Inc.; nor is this firm, or any employee, contract consultant, or officer thereof, otherwise affiliated with Atlas Resources, Inc. We also confirm that neither the employment of, nor payment of compensation received by UEDC in connection with this report, is on a contingent basis. Respectfully submitted, /s/ Robin Anthony ----------------- UEDC, Inc. 20 LEASE INFORMATION FOR FAYETTE AND GREENE COUNTIES, PENNSYLVANIA 21
Overriding Royalty Overriding Interest to the Royalty Effective Expiration Landowner Managing Interest to Prospect Name County Date* Date* Royalty General Partner 3rd Parties ----------------- ------------- ------------- ------------- ------------- --------------- ------------- 1. Allen #5 Fayette 12/16/2002 12/16/2003 12.5% 0% 0% 2. Allen/USX #8 Fayette 10/5/2000 HBP 12.5% 0% 0% 3. Allen/USX #9 Fayette 10/5/2000 HBP 12.5% 0% 0% 4. Blaney #2 Fayette 8/3/2001 8/3/2004 12.5% 0% 0% 5. Blaney #3 Fayette 8/3/2001 8/3/2004 12.5% 0% 0% 6. Blaney/USX #4 Fayette 10/5/2000 HBP 12.5% 0% 0% 7. Cardine #4 Fayette 12/30/1998 HBP 12.5% 0% 0% 8. Conrail #11 Fayette 1/25/1906 HBP 12.5% 0% 0% 9. Diamond #2 Fayette 9/7/2001 HBP 12.5% 0% 0% 10. E&N Land #1 Fayette 12/31/2002 12/31/2004 12.5% 0% 0% 11. E&N Land #2 Fayette 12/13/2002 12/31/2004 12.5% 0% 0% 12. Graham #6 Fayette 8/22/1911 HBP 12.5% 0% 0% 13. Hassibi #4 Fayette 3/30/2003 9/30/2003 12.5% 0% 0% 14. Hendricks #4 Fayette 1/6/1999 1/6/2004 12.5% 0% 0% 15. Jackson Farms #15 Fayette 10/14/1998 10/14/2003 12.5% 0% 0% 16. Jackson Farms #17 Fayette 10/14/1998 HBP 12.5% 0% 0% 17. Jackson Farms #22 Fayette 10/14/1998 HBP 12.5% 0% 0% 18. Jackson Farms #5 Fayette 10/14/1998 10/14/2003 12.5% 0% 0% 19. Jackson Farms #8 Fayette 10/14/1998 10/14/2003 12.5% 0% 0% 20. Krukowski #1 Fayette 5/19/2001 5/19/2006 12.5% 0% 0% 21. Langley #8 Fayette 6/16/2001 HBP 12.5% 0% 0% 22. Moore #8 Fayette 8/13/2002 HBP 12.5% 0% 0% 23. Moore #9 Fayette 8/13/2002 HBP 12.5% 0% 0% 24. Nichols #3 Fayette 8/2/1996 HBP 12.5% 0% 0% 25. Porter #10 Fayette 10/20/2002 10/20/2004 12.5% 0% 0% 26. Ronco/USX #2 Fayette 3/15/1999 HBP 12.5% 0% 0% 27. Rosa #5 Fayette 3/19/2001 HBP 12.5% 0% 0% 28. Stewart #11 Fayette 12/29/1998 HBP 12.5% 0% 0% 29. Stewart #9 Fayette 9/26/2002 HBP 12.5% 0% 0% 30. Veschio/USX #1 Fayette 10/5/2000 HBP 12.5% 0% 0% 31. Wolf #12 Fayette 12/3/2002 12/3/2004 12.5% 0% 0% 32. Yoder #24 Fayette 1/24/1906 HBP 12.5% 0% 0% Acres to be Assigned to Net Revenue Working Net the Prospect Name Interest Interest Acres Partnership ----------------- ------------- ------------- ----- ------------- 1. Allen #5 87.5% 100% 88 20 2. Allen/USX #8 87.5% 100% 2634 20 3. Allen/USX #9 87.5% 100% 2634 20 4. Blaney #2 87.5% 100% 44 20 5. Blaney #3 87.5% 100% 44 20 6. Blaney/USX #4 87.5% 100% 2634 20 7. Cardine #4 87.5% 100% 119 20 8. Conrail #11 87.5% 100% 145 20 9. Diamond #2 87.5% 100% 45 20 10. E&N Land #1 87.5% 100% 71 20 11. E&N Land #2 87.5% 100% 73 20 12. Graham #6 87.5% 100% 133 20 13. Hassibi #4 87.5% 100% 103 20 14. Hendricks #4 87.5% 100% 85 20 15. Jackson Farms #15 87.5% 100% 15 15 16. Jackson Farms #17 87.5% 100% 190 20 17. Jackson Farms #22 87.5% 100% 82 20 18. Jackson Farms #5 87.5% 100% 66 20 19. Jackson Farms #8 87.5% 100% 80 20 20. Krukowski #1 87.5% 100% 109 20 21. Langley #8 87.5% 100% 215 20 22. Moore #8 87.5% 100% 125 20 23. Moore #9 87.5% 100% 125 20 24. Nichols #3 87.5% 100% 111 20 25. Porter #10 87.5% 100% 76 20 26. Ronco/USX #2 87.5% 100% 294 20 27. Rosa #5 87.5% 100% 125 20 28. Stewart #11 87.5% 100% 67 20 29. Stewart #9 87.5% 100% 129 20 30. Veschio/USX #1 87.5% 100% 2634 20 31. Wolf #12 87.5% 100% 193 20 32. Yoder #24 87.5% 100% 260 20
- --------------- * HBP-Held by Production 22 LOCATION AND PRODUCTION MAPS FOR FAYETTE AND GREENE COUNTIES 23 [GRAPHIC OMITTED] 24 [GRAPHIC OMITTED] 25 [GRAPHIC OMITTED] 26 [GRAPHIC OMITTED] 27 [GRAPHIC OMITTED] 28 PRODUCTION DATA FOR FAYETTE AND GREENE COUNTIES, PENNSYLVANIA 29 The Production Data provided in the table below is not intended to imply that the wells to be drilled by the partnership will have the same results, although it is an important indicator in evaluating the economic potential of any well to be drilled by the partnership.
TOTAL MCF THROUGH TOTAL LATEST MOS 06/30/03 EXCEPT LOGGERS 30 DAY ID NUMBER OPERATOR WELL NAME DATE COMPLT'D ON LINE WHERE NOTED DEPTH PRODUCTION 1. 3 M.E. Davis Ben Lardin #1 4/8/1956 N/A N/A 3814 N/A 2. 10 Manufacturers Light & Heat Co Hogsett #9 10/21/1947 N/A N/A N/A N/A 3. 19 Greensboro Gas Co J.V.Thompson 10/17/1945 N/A N/A 3044 N/A 4. 41 Greensboro Gas Co Hogsett #2 1/1/1922 N/A N/A 1968 N/A 5. 42 Nollem Oil & Gas Corp. Lingle (Neff Heirs) #1 5/20/1944 N/A N/A 3473 N/A 6. 43 Nollem Oil & Gas Corp. Neff Heirs #1 8/23/1943 N/A N/A 4210 N/A 7. 57 Carnegie Natural Gas Co H.C.Frick Coke(Ralph)#2 2/5/1945 N/A 105,000/1963 2595 N/A 8. 58 Carnegie Natural Gas Co H.C.Frick Coke(Ralph)#1 7/22/1944 228 86,428/1963 2588 N/A 9. 60 Greensboro Gas Co Dearth #3 4/13/1905 N/A N/A 3143 N/A 10. 63 Manufacturers Light & Heat Co Hogsett #6 2/17/1945 N/A N/A 2793 N/A 11. 66 Manufacturers Light & Heat Co Hogsett #8 5/26/1947 N/A N/A 2475 N/A 12. 71 Peoples Natural Gas Co DiCarlo #1 N/A N/A N/A 1975 N/A 13. 120 Peoples Natural Gas Co Emery Dziak # 4/13/1945 N/A N/A 3489 N/A 14. 121 W. Burkland J.A. Baer #2 10/11/1937 N/A 215,000/1980 3610 N/A 15. 140 Atlas (Castle Gas Co) Duff, Lauretta 3/29/1905 N/A 184,000/1990 1,361 N/A 16. 184 Castle Gas Co Jacobs #5 10/1/1943 N/A 93,000 N/A N/A 17. 185 Atlas (Castle Gas Co) Dearth #1 11/23/1917 N/A 1,373,000/1990 2,384 28 18. 186 Atlas (Castle Gas Co) Conrail #1 12/2/1910 N/A 427,000/1990 3,155 N/A 19. 257 Atlas (Castle Gas Co) Graham, A. #1 N/A N/A 289,000/1990 N/A N/A 20. 20013 William E. Snee & Orville Eberly Szabo #1 8/20/1960 N/A N/A 2,640 N/A 21. 20021 Peoples Natural Gas Co C. Yuras #1 3/17/1949 N/A 149,000/1974 3493 N/A 22. 20059 M.C.Brumage DiCarlo #2 12/29/1967 N/A N/A 3093 N/A 23. 20122 R. Taylor Mosier R. T. Mosier #1 3/11/1972 N/A N/A 2642 N/A 24. 20168 R. Taylor Mosier R.T. Mosier #2 1/10/1977 N/A N/A 2600 N/A 25. 20203 Total Resources Sloan/Thompson #1 8/31/1978 N/A N/A 4060 N/A 26. 20244 Atlas (Castle Gas Co) Yoder, E. #2 9/13/1979 N/A 52,000/1990 N/A 278 27. 20277 Ashtola Production Co R.Cerullo #1 7/13/1981 N/A N/A 4531 N/A 28. 20285 Atlas Lambert/USX #2 6/7/2001 24 35,615 4,122 900
30 The Production Data provided in the table below is not intended to imply that the wells to be drilled by the partnership will have the same results, although it is an important indicator in evaluating the economic potential of any well to be drilled by the partnership.
TOTAL MCF THROUGH TOTAL LATEST MOS 06/30/03 EXCEPT LOGGERS 30 DAY ID NUMBER OPERATOR WELL NAME DATE COMPLT'D ON LINE WHERE NOTED DEPTH PRODUCTION 29. 20313 Ashtola Production Co D'Isodoro #1 12/7/1982 N/A N/A 3863 N/A 30. 20742 Kriebel Gas Inc Fairbank Rod & Gun #1 11/5/1996 N/A N/A 3895 N/A 31. 20894 Atlas Zitney #1A 2/4/1997 53 19,421 4,077 216 32. 20919 N/A USX (Coalbed methane we) N/A N/A N/A N/A N/A 33. 20962 Atlas Lavery #1 1/13/1998 64 38,283 4,476 267 34. 20971 Atlas Swetz #1 1/28/1998 62 6,565 6,010 55 35. 20991 Atlas DiCarlo #1 3/12/1998 60 13,577 4,439 76 36. 20992 Atlas Fette/Davis/Sunyak #1 3/30/1998 61 76,924 6,015 896 37. 20995 Atlas Kutek #1 11/25/1998 52 26,334 3,560 382 38. 21001 Atlas Kovach, K. #1 1/2/1999 50 94,725 4,002 1,195 39. 21004 Atlas Winter, J. #1 1/30/1999 52 3,876 4,110 41 40. 21040 Atlas Howe #1 5/4/1999 48 80,303 3,988 651 41. 21072 W.Burkland Yoho #1 N/A N/A N/A N/A N/A 42. 21075 Atlas Cerullo #1 3/7/1999 47 4,353 3,815 59 43. 21076 Atlas East Huntingdon Corp #1 3/27/1999 50 9,933 3,866 123 44. 21078 W.Burkland R. Jackson #1 N/A N/A N/A N/A N/A 45. 21080 Atlas Bowers/Hogsett #2 2/24/1999 49 33,780 3,528 506 46. 21105 Atlas Kovach #2A 2/3/2000 38 114,601 3,960 2,552 47. 21107 Atlas McGill #1 12/8/1999 41 37,582 4,052 431 48. 21116 Atlas Johnston, E.#1 3/25/2000 37 83,521 4,270 1,271 49. 21147 Atlas Krepps #1 4/1/2000 38 22,664 4,210 411 50. 21161 Atlas Hall/Hogsett #1 9/29/2000 28 43,256 3,970 721 51. 21165 Atlas Hoehn #1 9/25/2000 32 58,053 3,875 1,108 52. 21166 Atlas Hall/Hogsett #7 9/14/2000 33 29,107 4,059 726 53. 21198 Atlas East Huntingdon Corp #2 10/18/2000 32 26,940 3,909 776 54. 21207 Atlas Hall #4 11/11/2000 30 39,115 4,032 718 55. 21224 Atlas Crable #1 3/26/2001 25 22,643 3,995 764 56. 21232 Atlas Fairbank Rod & Gun #2 1/11/2001 28 1,824 3,973 68
31 The Production Data provided in the table below is not intended to imply that the wells to be drilled by the partnership will have the same results, although it is an important indicator in evaluating the economic potential of any well to be drilled by the partnership.
TOTAL MCF THROUGH TOTAL LATEST MOS 06/30/03 EXCEPT LOGGERS 30 DAY ID NUMBER OPERATOR WELL NAME DATE COMPLT'D ON LINE WHERE NOTED DEPTH PRODUCTION 57. 21233 Atlas Soberdash #2 1/6/2001 27 3,369 3,455 109 58. 21237 Atlas Fairbank Rod & Gun #1 1/19/2001 16 9,165 4,055 204 59. 21238 Atlas Soberdash #1 2/22/2001 27 7,539 3,514 276 60. 21252 Atlas Skovran #6 3/19/2001 25 69,748 4,066 821 61. 21255 Atlas Faverio #1 7/2/2001 22 2,776 4,113 184 62. 21263 Atlas Frankhouser #1 3/26/2001 25 64,527 4,516 1,173 63. 21265 Atlas Girolami #1 5/30/2001 23 36,866 4,110 1,047 64. 21287 Atlas Hall/Hogsett #5 6/13/2001 23 61,647 3,916 1,753 65. 21288 Atlas Frankhouser #2 9/12/2001 7 33,776 4,516 757 66. 21289 Atlas Cardine #1 7/18/2001 22 7,159 4,110 461 67. 21292 Atlas Skovran #8 7/7/2001 23 76,115 2,152 1,908 68. 21296 Atlas DiCarlo #4 6/20/2001 23 81,475 3,910 1,280 69. 21297 Atlas DiCarlo #5 6/25/2001 22 20,949 3,970 699 70. 21303 Atlas Thomas #2 7/31/2001 21 12,441 3,885 328 71. 21304 Atlas Swetz #2 11/3/2001 20 20,350 4,260 638 72. 21305 Atlas Pollick #3 8/15/2001 20 17,914 4,030 565 73. 21307 Atlas Hoehn #3 9/27/2001 20 94,884 3,856 3,237 74. 21309 Atlas Hoehn #5 8/10/2002 8 29,457 4,250 2,177 75. 21310 Atlas Crable/Hogsett #2 8/15/2001 20 46,067 3,977 1,343 76. 21312 Atlas Brant #1 11/27/2001 N/A N/A 3,710 N/A 77. 21313 Atlas Sherrin #1 10/18/2001 19 7,621 3,720 366 78. 21314 Atlas Thomas #1 8/5/2001 21 24,567 3,889 555 79. 21320 Atlas Hmelyar #1 8/24/2001 7 2,741 4,208 303 80. 21322 Atlas McGill #4 9/30/2001 15 34,146 3,960 1,991 81. 21325 Atlas Darr/USX #1 10/8/2001 9 4,178 4,000 168 82. 21326 Atlas Skovran #7 9/10/2001 21 29,152 4,063 985 83. 21328 Atlas Hall/Hogsett #10 9/2/2001 21 44,088 4,176 1,518 84. 21333 Atlas Darr/USX #2 2/18/2002 9 13,861 2,250 302
32 The Production Data provided in the table below is not intended to imply that the wells to be drilled by the partnership will have the same results, although it is an important indicator in evaluating the economic potential of any well to be drilled by the partnership.
TOTAL MCF THROUGH TOTAL LATEST MOS 06/30/03 EXCEPT LOGGERS 30 DAY ID NUMBER OPERATOR WELL NAME DATE COMPLT'D ON LINE WHERE NOTED DEPTH PRODUCTION 85. 21342 Atlas Szuhay #1 12/10/2001 16 61,157 4,550 1,703 86. 21343 Atlas Szuhay #2 10/14/2001 18 5,438 4,492 147 87. 21344 Atlas Szuhay #3 4/30/2002 13 17,200 4,362 909 88. 21357 Atlas Bashour #1 12/18/2001 16 216,674 4,558 6,010 89. 21358 Atlas Skovran #10 12/4/2001 11 10,366 4,500 929 90. 21363 Atlas Brock #3 10/25/2001 16 15,777 3,756 69 91. 21365 Atlas Barber #2 11/21/2001 13 10,501 4,395 401 92. 21366 Atlas Barber #1 11/14/2001 13 14,033 4,349 608 93. 21368 Atlas Conrail #4 11/9/2002 10 8,077 3,850 406 94. 21369 Atlas Hall #9 12/11/2001 16 37,366 3,862 1,695 95. 21370 Atlas Hall #8 12/3/2001 13 18,250 4,010 768 96. 21372 Atlas Podolinski #1 1/26/2002 13 11,310 3,872 506 97. 21376 Atlas National Mines #3 2/13/2002 13 16,127 4,201 1,301 98. 21382 Atlas Labash/Myers #3 1/9/2003 3 57 4,389 19 99. 21384 Atlas Marcinek #1 1/6/2002 8 5,962 3,907 335 100. 21398 Atlas Hall #11 (P&A'd) 1/31/2002 N/A N/A 4,203 N/A 101. 21400 Atlas Newcomer #2 2/28/2002 12 9,055 2,175 205 102. 21401 Atlas Newcomer #1 1/26/2002 12 1,360 4,446 47 103. 21402 Atlas National Mines #6 5/29/2002 11 40,514 4,250 2,649 104. 21403 Atlas National Mines Corp. #5 11/21/2002 5 15,617 4,120 3,475 105. 21404 Atlas National Mines #4 4/3/2002 12 58,768 4,320 619 106. 21409 Atlas McArdle #1 2/4/2002 12 18,310 4,054 1,059 107. 21413 Atlas Mallick #1 2/28/2002 9 17,468 4,183 572 108. 21416 Atlas Gilleland #1 1/11/2002 7 4,653 4,179 531 109. 21420 Atlas Gilleland #2 6/18/2002 7 2,386 4,143 236 110. 21435 Atlas Young #7A 3/29/2002 10 2,093 3,680 93 111. 21439 Atlas Gaggiani #3A 5/8/2002 11 4,558 2,160 169 112. 21440 Atlas Gaggiani #1 3/27/2002 11 5,347 4,710 308
33 The Production Data provided in the table below is not intended to imply that the wells to be drilled by the partnership will have the same results, although it is an important indicator in evaluating the economic potential of any well to be drilled by the partnership.
TOTAL MCF THROUGH TOTAL LATEST MOS 06/30/03 EXCEPT LOGGERS 30 DAY ID NUMBER OPERATOR WELL NAME DATE COMPLT'D ON LINE WHERE NOTED DEPTH PRODUCTION 113. 21443 Atlas Young #6 4/10/2002 10 12,163 3,860 358 114. 21453 Atlas Rider & Ashton #1 5/15/2002 11 2,968 4,426 133 115. 21460 Atlas Henderson #1 5/21/2002 8 3,449 3,880 234 116. 21461 Atlas Rittenhouse #2 12/13/2002 5 8,560 3,912 1,312 117. 21465 Atlas Skovran #11 6/26/2002 11 5,596 4,564 463 118. 21468 Atlas Hoehn #4 6/12/2002 11 36,024 3,800 1,939 119. 21469 Atlas Conrail #5 6/5/2002 10 13,201 4,300 857 120. 21470 Atlas Hall/Hogsett #6 5/29/2002 10 28,963 4,452 2,043 121. 21476 Atlas Elder #3 12/10/2002 5 3,584 4,270 303 122. 21483 Atlas Diamond #1 6/25/2002 N/A N/A 4,209 N/A 123. 21491 Atlas Leckrone/USX #1(P&A'd) 7/17/2002 N/A N/A 3,940 N/A 124. 21503 Atlas Rittenhouse #1 3/29/2003 15 13,549 3,450 475 125. 21506 Atlas Gilleland #3 7/31/2002 7 10,442 4,027 1,254 126. 21509 Atlas Howe #2 9/4/2002 8 20,357 1,870 274 127. 21511 Atlas Hall/Hogsett #3 8/16/2002 5 8,598 3,910 894 128. 21513 Atlas Cobert #1 8/15/2002 9 11,166 2,481 229 129. 21516 Atlas Conrail #6 9/19/2002 7 6,644 4,262 848 130. 21527 Atlas Nichols #1 8/16/2002 7 5,655 4,160 524 131. 21530 Atlas Smith #8 1/3/2003 4 2,476 4,090 823 132. 21539 Atlas National Mines Corp. #8 9/18/2002 7 6,091 4,370 676 133. 21551 Atlas Zitney #2 2/2/2003 3 3,455 4,115 1,654 134. 21552 Atlas Cobert #2 3/4/2003 3 5,863 2,405 1,898 135. 21556 Atlas Hoehn Unit #2A 10/9/2001 17 46,903 3,850 1,498 136. 21562 Atlas Kutek #2 1/29/2003 3 1,050 3,780 341 137. 21569 Atlas Rosa #1 1/20/2003 3 6,835 4,030 3,021 138. 21570 Atlas Szuhay #4 12/20/2002 4 1,838 4,410 460 139. 21571 Atlas Stewart #6 2/21/2003 2 4,077 4,250 2,818 140. 21575 Atlas Elder #2 12/4/2002 5 3,743 4,000 751
34 The Production Data provided in the table below is not intended to imply that the wells to be drilled by the partnership will have the same results, although it is an important indicator in evaluating the economic potential of any well to be drilled by the partnership.
TOTAL MCF THROUGH TOTAL LATEST MOS 06/30/03 EXCEPT LOGGERS 30 DAY ID NUMBER OPERATOR WELL NAME DATE COMPLT'D ON LINE WHERE NOTED DEPTH PRODUCTION 141. 21577 Atlas McGill #5 11/22/2002 5 9,619 3,910 1,780 142. 21579 Atlas Gilleland #4 11/26/2002 5 1,895 4,250 370 143. 21587 Atlas Wivell #3 1/11/2003 3 20,328 4,059 7,000 144. 21588 Atlas Wivell #1 1/25/2003 3 9,312 4,030 4,685 145. 21591 Atlas National Mines #14 12/4/2002 5 6,683 4,370 2,010 146. 21594 Atlas Free/Ogle #1 1/3/2003 1/4/1900 10,924 4,027 3,511 147. 21598 Atlas Marian #3 2/15/2003 2 1,656 4,300 1,473 148. 21599 Atlas Carroll #3 2/4/2003 2 1,945 4,210 1,018 149. 21601 Atlas Debord #5 1/24/2003 3 6,310 3,860 2,430 150. 21605 Atlas Debord #2 2/6/2003 3 1,425 4,070 471 151. 21606 Atlas Conrail #9 1/10/2003 3 3,562 3,850 1,188 152. 21607 Atlas Conrail #8 1/5/2003 4 9,292 3,950 3,238 153. 21613 Atlas Jackson Farms #2 4/10/2003 N/A N/A 3,010 N/A 154. 21614 Atlas Debord #3 2/1/2003 3 7,043 4,080 3,421 155. 21615 Atlas Debord #4 1/19/2003 3 10,163 3,920 3,518 156. 21621 W. Burkland E.Dziak #2 1/7/2003 N/A N/A 4,241 N/A 157. 21624 Atlas Erjavec #1 3/12/2003 1 2,089 4,510 2,089 158. 21630 Atlas Langley #1 2/25/2003 N/A N/A 4,420 N/A 159. 21644 Atlas Yoder #17 2/15/2003 1 595 4,220 595 160. 21645 Atlas Yoder #19 3/3/2003 1 27 3,015 27 161. 21646 Atlas Yoder #18 2/25/2003 1 500 4,120 500 162. 21650 Atlas Yoder #20 3/11/2003 N/A N/A 4,070 N/A 163. 21652 Atlas Jackson Farms #6 3/4/2003 2 2,609 4,550 2,416 164. 21681 Atlas Jackson Farms #19 4/2/2003 N/A N/A 4,070 N/A 165. 90018 Manufacturers Light & Heat Co. Alva J. Wolfe #L-4190 1/15/1954 N/A N/A 542 N/A 166. 90059 Greensboro Gas Co Hogsett #4 10/23/1923 N/A N/A 3045 N/A 167. 90066 Greensboro Gas Co Hogsett #1 1/1/1911 N/A N/A 3117 N/A 168. 90067 Greensboro Gas Co Hogsett #3 6/19/1923 N/A N/A 3196 N/A
35 The Production Data provided in the table below is not intended to imply that the wells to be drilled by the partnership will have the same results, although it is an important indicator in evaluating the economic potential of any well to be drilled by the partnership.
TOTAL MCF THROUGH TOTAL LATEST MOS 06/30/03 EXCEPT LOGGERS 30 DAY ID NUMBER OPERATOR WELL NAME DATE COMPLT'D ON LINE WHERE NOTED DEPTH PRODUCTION 169. 90068 Greensboro Gas Co Christopher #1 1/15/1915 N/A N/A 3100 N/A 170. 90069 Greensboro Gas Co Christopher #2 2/13/1917 N/A N/A 3065 N/A 171. 90071 Greensboro Gas Co John Gibson #2 3/18/1920 N/A N/A 3108 N/A 172. 90072 Greensboro Gas Co Conwell #2 3/5/1910 N/A N/A 3240 N/A 173. 90073 Greensboro Gas Co E. Franks #1 9/21/1917 N/A N/A 2957 N/A 174. 90075 Greensboro Gas Co T. Acklin #120 5/28/1907 N/A N/A 2966 N/A 175. 90080 Greensboro Gas Co Krepps N/A N/A N/A 3099 N/A 176. 90081 Greensboro Gas Co Krepps #2 10/21/1910 N/A N/A 3106 N/A 177. 90088 Greensboro Gas Co L.W. Porter #113 9/1/1907 N/A N/A 3004 N/A 178. 90092 Greensboro Gas Co W.J. Stewart #1 11/14/1906 N/A N/A 2925 N/A 179. 90094 Greensboro Gas Co W.J. Stewart #2 8/1/1910 N/A N/A 3090 N/A 180. 90095 Greensboro Gas Co J.V. Thompson #1 6/17/1910 N/A N/A 3309 N/A 181. 90096 Greensboro Gas Co J.C. Vernon #144 9/1/1908 N/A N/A 2333 N/A 182. 90097 Greensboro Gas Co Vernon Heirs 3/23/1905 N/A N/A 2930 N/A 183. 90100 Greensboro Gas Co Adam M. Jacobs #4 5/23/1917 N/A N/A 2751 N/A 184. 90101 Greensboro Gas Co Christopher #3 2/3/1923 N/A N/A 3206 N/A 185. 90106 Greensboro Gas Co A.M.R. Jacobs #3 1/19/1917 N/A N/A 1540 N/A 186. 90162 Greensboro Gas Co R. Fleming #1 4/1/1905 N/A N/A 4054 N/A 187. 90163 Greensboro Gas Co J.S. Rittenhouse #1 3/30/1905 N/A N/A 3788 N/A 188. 90169 Greensboro Gas Co J.R. Colley 4/1/1905 N/A N/A 4319 N/A 189. F22816 N/A Hazen #1 N/A N/A N/A 3768 N/A 190. FGN14 N/A H.C. Frick #1 before 1935 N/A N/A est 1700 N/A 191. FL38 N/A Jacobs N/A N/A N/A N/A N/A 192. FL49 N/A N/A N/A N/A N/A N/A N/A 193. G169 Greensboro Gas Co J.W. Hibbs #1 21/2/1909 N/A N/A 2885 N/A 194. G174 Greensboro Gas Co J.E. Craft #1 9/17/1909 N/A N/A 3263 N/A 195. G194 Greensboro Gas Co J.V. Thompson #2 10/13/1910 N/A N/A 3010 N/A 196. G333 Greensboro Gas Co Shanefelter #1 9/4/1915 N/A N/A 4040 N/A
36 The Production Data provided in the table below is not intended to imply that the wells to be drilled by the partnership will have the same results, although it is an important indicator in evaluating the economic potential of any well to be drilled by the partnership.
TOTAL MCF THROUGH TOTAL LATEST MOS 06/30/03 EXCEPT LOGGERS 30 DAY ID NUMBER OPERATOR WELL NAME DATE COMPLT'D ON LINE WHERE NOTED DEPTH PRODUCTION 197. G393 Greensboro Gas Co Shanefelter #2 2/1/1917 N/A N/A 3636 N/A 198. G469 Greensboro Gas Co Flemming #2 5/15/1919 N/A N/A 3335 N/A 199. P1230 N/A N/A N/A N/A N/A N/A N/A 200. P1233 Greensboro Gas Co N/A 9/30/1909 N/A N/A 3125 N/A 201. P1236 Greensboro Gas Co N/A 6/27/1906 N/A N/A 2838 N/A 202. P1237 Greensboro Gas Co J.M. West #1 6/18/1909 N/A N/A 2875 N/A 203. P1239 Greensboro Gas Co Dearth #1 8/12/1907 N/A N/A N/A N/A 204. P1240 Greensboro Gas Co Porter #1 9/5/1907 N/A N/A 3004 N/A 205. P1241 Greensboro Gas Co Aeklin #1 1/11/1910 N/A N/A 2330 N/A 206. P1242 Greensboro Gas Co Porter #2 1/17/1914 N/A N/A 2974 N/A 207. P1247 Greensboro Gas Co Lightey #1 12/8/1913 N/A N/A 3121 N/A 208. P1269 Monongahela Natural Gas Co. J. Hackney 7/17/1909 N/A N/A 3140 N/A 209. P1270 Manufacturers Light & Heat Co. Hackney 12/16/1916 N/A N/A 3549 N/A 210. P1272 Greensboro Gas Co N. Dearth 9/14/1907 N/A N/A 2328 N/A 211. P1274 N/A N/A N/A N/A N/A N/A N/A 212. P1275 Greensboro Gas Co A. Arensburg #2 11/25/1907 N/A N/A 2397 N/A 213. P1276 Greensboro Gas Co A. Arnesburg #1 11/15/1907 N/A N/A 2418 N/A 214. P1281 Peoples Natural Gas Co Hackney #3 7/1/1921 N/A N/A N/A N/A 215. P16493 Greensboro Gas Co A. Jacobs #3 9/24/1922 N/A N/A 1684 N/A 216. P21257 C.D. White & Co. V. Pollack #1 4/7/1939 N/A N/A 2530 N/A 217. P22272 Wahler & Powers Reynolds #3 6/29/1940 N/A N/A N/A N/A 218. P23858 N/A McWilliams #1 before 1935 N/A N/A est 2120 N/A 219. P23860 N/A H.C. Frick before 1935 N/A N/A est 2300 N/A 220. P23862 N/A T. Hoover before 1935 N/A N/A est 2300 N/A 221. P23863 N/A Unknown before 1935 N/A N/A est 2150 N/A 222. P24176 Forest Oil Co W. Larden about 1900 N/A N/A N/A N/A 223. P24184 N/A Hess N/A N/A N/A N/A N/A 224. P24185 N/A Hoover N/A N/A N/A N/A N/A
37 The Production Data provided in the table below is not intended to imply that the wells to be drilled by the partnership will have the same results, although it is an important indicator in evaluating the economic potential of any well to be drilled by the partnership.
TOTAL MCF THROUGH TOTAL LATEST MOS 06/30/03 EXCEPT LOGGERS 30 DAY ID NUMBER OPERATOR WELL NAME DATE COMPLT'D ON LINE WHERE NOTED DEPTH PRODUCTION 225. P24186 N/A Hoover N/A N/A N/A N/A N/A 226. P24314 L. Williams N/A 12/1/1929 N/A N/A 2799 N/A 227. P24514 Monongahela Natural Gas Co. H. Newcomer 12/24/1907 N/A N/A 3389 N/A 228. P24515 Monongahela Natural Gas Co. N/A 1/27/1909 N/A N/A 2509 N/A 229. P25173 Monongahela Natural Gas Co. G. Acklin 12/17/1910 N/A N/A 3096 N/A 230. P26665 Nollem Oil & Gas Corp. B.F. Johnson #1 9/22/1944 N/A N/A 3598 N/A 231. P27173 Nollem Oil & Gas Corp. Neff Heirs #2 7/20/1945 N/A N/A 3551 N/A 232. P27648 R.Murray et al Hibbs #1 5/19/1946 N/A N/A 1913 N/A 233. P27813 R.Murray et al Hibbs Heirs #2 9/4/1946 N/A N/A 3087 N/A 234. P29372 E.C. Metzler W. Lardin #1 1/16/1950 N/A N/A 3702 N/A 235. PNG3326 Peoples Natural Gas Co J.A. Baer #1 2/26/1942 N/A N/A 3520 N/A 236. PNG3406 Peoples Natural Gas Co W.I. Moore #3406 6/8/1943 N/A N/A 3566 N/A 237. PNG3426 Peoples Natural Gas Co J.N. Randolph #1 1/19/1944 N/A N/A 3869 N/A 238. PNG3603 Peoples Natural Gas Co Republic Colleries #1 7/27/1945 N/A N/A 2989 N/A 239. PNG3619 Peoples Natural Gas Co Girolami #1 9/25/1945 N/A N/A 3258 N/A 240. PNG3664 Peoples Natural Gas Co McCann #1 10/28/1946 N/A N/A N/A N/A 241. PNG3671 Peoples Natural Gas Co Podolinski #1 9/27/1946 N/A N/A N/A N/A 242. PNG3672 Peoples Natural Gas Co H.Hogsett #3 12/10/1946 N/A N/A 3212 N/A 243. PNG3724 Peoples Natural Gas Co H.Hogsett #4 8/14/1947 N/A N/A 3327 N/A 244. PNG3860 Peoples Natural Gas Co N/A 7/27/1949 N/A N/A 3108 N/A 245. PNG3924 Peoples Natural Gas Co C. Yuras #2 8/8/1950 N/A N/A 3501 N/A
38 UEDC'S GEOLOGIC EVALUATION FOR THE CURRENTLY PROPOSED WELLS IN FAYETTE AND GREENE COUNTIES, PENNSYLVANIA 39 GEOLOGIC EVALUATION ATLAS AMERICA PUBLIC #12-2003 LIMITED PARTNERSHIP Fayette Prospect Area Pennsylvania Dated: May 6, 2003
Program proposed by: Report submitted by: ATLAS RESOURCES, INC. UEDC 311 Rouser Road United Energy Development Consultants, Inc. P.O. Box 611 1715 Crafton Blvd. Moon Township, PA 15108 Pittsburgh, PA 15205
LOCATION MAP - AREA OF INTEREST [GRAPHIC OMITTED] TABLE OF CONTENTS
LOCATION MAP - AREA OF INTEREST .......................................... 1 TABLE OF CONTENTS ........................................................ 1 INVESTIGATION SUMMARY .................................................... 2 OBJECTIVE ............................................................... 2 AREA OF INVESTIGATION ................................................... 2 METHODOLOGY ............................................................. 2 PROSPECT AREA HISTORY .................................................... 2 DRILLING ACTIVITY ....................................................... 2 GEOLOGY ................................................................. 2 STRATIGRAPHY, LITHOLOGY & DEPOSITION .................................. 2 RESERVOIR CHARACTERISTICS ............................................. 4 PRODUCTION .............................................................. 4 CONCLUSION .............................................................. 5 DISCLAIMER .............................................................. 5 NON-INTEREST ............................................................ 5
40 INVESTIGATION SUMMARY OBJECTIVE The purpose of the following investigation is to evaluate the geologic feasibility and further development of the Fayette Prospect Area as proposed by Atlas Resources, Inc. ("Atlas"). AREA OF INVESTIGATION A portion of this prospect area, herein identified for drilling in Atlas America Public #12-2003 Limited Partnership, contains acreage in Luzerne, Redstone, Menallen, Nicholson, and Franklin Townships in Fayette County, located in western Pennsylvania. Thirty-two (32) drilling prospects have currently been designated for this program in the prospect area, which will be targeted to produce natural gas from Mississippian and Upper Devonian reservoirs, found at depths from 1300 feet to 4500 feet beneath the earth's surface. These will be the only prospects evaluated for the purposes of this report. METHODOLOGY Atlas provided the data incorporated into this report. Geological mapping and the interpretations by Atlas geologists were also examined. Available "electric" log, completion and production data on "key" wells within and adjacent to the defined prospect area were utilized to determine productive and depositional trends PROSPECT AREA HISTORY DRILLING ACTIVITY The proposed drilling area lies within a region of southwestern Pennsylvania, which has been active for the past six years in terms of exploration for, and exploitation of natural gas reserves. Development within and adjacent to the Fayette Prospect Area has continued steadily since 1996. Over two hundred seventy five (275) wells have been drilled in the area during this period. Atlas has encountered favorable drilling and production results while solidifying a strong acreage position of nearly 50,000 acres, as Atlas continues to identify and extend productive trends. Drilling is ongoing as of the date of this report with recent wells displaying favorable initial drilling and completion results. The area of proposed drilling is situated in portions of Fayette and Greene Counties that have had established production from shallower, historic pay zones. Atlas will target deeper pay zones when locating a drill site within the "old shallow field area". Otherwise, Atlas will maintain a minimum of 1000 feet from any existing producing well in the area. GEOLOGY STRATIGRAPHY, LITHOLOGY & DEPOSITION The Mississippian reservoirs currently producing in the Fayette Prospect Area are the Burgoon Sandstone (lower Big Injun) and the 2nd Gas Sand. The Burgoon Sandstone is part of the massive Big Injun fluvial-deltaic sand system, which extends from eastern Kentucky through West Virginia into southwestern Pennsylvania. This reservoir is an historic producing zone in this region, with some wells still producing long beyond fifty years. There is not much history of production from the 2nd Gas Sand in this area. The Upper Devonian reservoirs consist of three groups of sands, Upper Venango, Lower Venango and Bradford. Each of these "Groups" has multiple reservoirs making up their total rock section. The Upper Venango Group consists of the Gantz Sand and the Fifty Foot Sand. The Lower Venango Group consists of the Fifth Sand and the Bayard Sand. Depositional environments of these Upper and Lower Venango Group sands are of near shore to offshore marine settings related to the last major advance of the Catskill Delta. The Bradford Group consists of the Lower Warren Sand, Upper Speechley Sand, Lower Speechley Sand, Upper Balltown Sand and the First Bradford Sand. Depositional environments of these sands are offshore marine, pro-delta and basin floor settings related to the intermediate advance of the Catskill Delta. 41 Stratigraphically, in descending order, the potentially productive units of the Mississippian and Upper Devonian Groups are: 1) Burgoon, 2) 2nd Gas Sand, 3) Gantz, 4) Fifty Foot, 5) Fifth, 6) Bayard, 7) L.Warren, 8) U.Speechley, 9) L.Speechley, 10) U. Balltown, 11) First Bradford Sand Stratigraphic relationships are illustrated in the diagram: [GRAPHIC OMITTED] o The Burgoon Sandstone is a fine to medium grained, medium to massively bedded, light-gray sandstone ranging in thickness from 200-250 feet. Average porosity values for this sand range from 6% to 12% regionally. It is not uncommon to encounter porosities as high as 20% and attendant producible natural open flows from this sand. Tracking these producible natural open flow trends is targeted for further development. Also, this zone does produce water in certain locales within the Fayette Prospect Area. This reservoir is considered a secondary target in the natural open flow trend areas. o The 2nd Gas Sand of this region has limited areal extent and therefore is not discussed in the literature regarding lithology, thickness etc. It can be inferred from underlying and overlying sands that it is probably a fine to very fine grained, light gray sand. Subsurface mapping indicates that the sand can achieve a thickness of twenty (20) feet. Average porosity values for this sand range from 10% to 13% when this zone is present in the area. Peak porosities of 17% have been encountered within the prospect area. This reservoir is considered to be a secondary target when encountered. o The Gantz Sand is a white to light-gray, medium to coarse-grained sandstone ranging in thickness from a few feet to over sixty (60) feet. Average porosity values for this sand range from 5% to 10% regionally. Within the area of investigation, porosities in excess of 13% occur within localized trends characterized by producible natural open flows. These trends are targeted for future development. This reservoir is considered a primary target in the natural open flow trend areas. o The Fifty Foot Sand is a white to light gray, thinly bedded, fine-grained sandstone ranging in thickness from ten (10) to thirty (30) feet. Average porosity values for this sand range from 5% to 8% regionally. Within the prospect area, porosities in excess of 12% occur within localized trends targeted for future development. This sand reservoir is considered a secondary target. o The Fifth Sand is a white to light gray, very fine to fine grained sandstone ranging in thickness from a few feet to forty (40) feet. Within the main Fifth fairway, porosity values average from 9% to 15%. This sand is considered a primary target and will be exploited in future development. o The Bayard Sand in the prospect area ranges in thickness from a few feet to more than sixty (60) feet. Average porosity values range from 5% to 12% for this fine to coarse-grained sandstone. Discrete reservoirs within the sand have been identified and mapped. Gas shows in the member sandstones delineate trends within the prospect area and will be targeted for future development. This sand is considered a primary target. o The Lower Warren Sand is a primary target in the prospect area. Average thickness for this sand ranges from zero (0) feet to over forty (40) feet. Porosities average between 8% and 12% in the area. Gas shows are commonly found in this sand, which is probably a fine-grained, well-sorted sand. This reservoir is targeted for future development. o The Upper Speechley Sand is considered a secondary target with average thickness ranging from two (2) feet to ten (10) feet over much of the prospect area. Gas shows from this sand are common throughout the area and the zone is combined with other zones when treated. o The Lower Speechley Sand is a primary target in the area with reservoir thickness ranging from zero (0) to over forty (40) feet. Average porosity values range from 5% to 12% where the sand is present. Significant natural and after treatment flows from this sand have been encountered. This sand is being targeted throughout the prospect area. o The Upper Balltown Sand is currently being produced in a few wells in the prospect area. The zone is a siltstone with fracture-enhanced porosity, based on log interpretation, and has associated gas shows. This sand is considered a secondary target and is usually combined with other zones when treated. o The First Bradford Sand, like the Balltown above, is currently being produced in a few wells in the prospect area. This silty-sand does have porosity up to 10% in the area and is considered to be a secondary target when encountered. 42 RESERVOIR CHARACTERISTICS Petroleum reservoirs are formed by the presence of an impermeable barrier trapping commercial quantities of natural gas in a more permeable medium. In the Mississippian and Upper Devonian reservoirs, this occurs either stratigraphically when a permeable sand containing hydrocarbons encounters impermeable shale or when permeable sand changes gradually into non-permeable sand by a cementation process known as "diagenesis". Thus, this type of trap represents cemented-in hydrocarbon accumulations. [GRAPHIC OMITTED] Electric well logs can be used in conjunction with production to interpret reservoir parameters. When sandstones in the Mississippian and Upper Devonian reservoirs develop porosity in excess of 8%, or a bulk density of 2.50 or less, the permeability of the reservoir can become great enough to allow commercial production of natural gas. Small, naturally occurring cracks in the formation, referred to as micro-fractures, can also enhance permeability. A gamma, bulk density, neutron, induction and temperature log suite showing sand development in both the Mississippian and Upper Devonian reservoirs is illustrated. The temperature log shown in the illustration at left identifies where gas is entering the wellbore. Evidence of a temperature "kick" or cooling is also an indication of enhanced permeability and the willingness of the reservoir to produce natural gas. PRODUCTION The Fayette prospect area produces from a number of reservoirs of different age and type. Each well has a unique combination of these reservoirs yielding different production declines. While Atlas anticipates production from each reservoir to be comparable to like reservoirs historically produced throughout the Appalachian Basin, a model decline curve for this prospect area is not included due to the multiple sets of commingled reservoirs exclusively found in this area. 43 STATEMENTS CONCLUSION UEDC has conducted a geologic feasibility study of the drilling area for Atlas America Public #12-2003 Limited Partnership, which will consist of developmental drilling of Lower Mississippian and Upper Devonian reservoirs primarily in Fayette County, Pennsylvania. It is the professional opinion of UEDC that the drilling of the thirty-two wells by Atlas America Public #12- 2003 Limited Partnership is supported by sufficient geologic and engineering data. DISCLAIMER For the purpose of this evaluation, UEDC did not visit any leaseholds or inspect any of the associated production equipment. Likewise, UEDC has no knowledge as to the validity of title, liabilities, or corporate matters affecting these properties. UEDC does not warrant individual well performance. NON-INTEREST We hereby confirm that UEDC is an independent consulting firm and that neither this firm or any of it's employees, contract consultants, or officers has, or is committed to acquire any interest, directly or indirectly, in Atlas Resources, Inc.; nor is this firm, or any employee, contract consultant, or officer thereof, otherwise affiliated with Atlas Resources, Inc. We also confirm that neither the employment of, nor payment of compensation received by UEDC in connection with this report, is on a contingent basis. Respectfully submitted, /s/ Robin Anthony ----------------- UEDC, Inc. 44 LEASE INFORMATION FOR ARMSTRONG AND INDIANA COUNTIES, PENNSYLVANIA, 45
Overriding Overriding Royalty Interest Royalty Net Effective Expiration Landowner to the Managing Interest to 3rd Revenue Prospect Name County Date* Date* Royalty General Partner Parties (1) Interest ------------------------------------------------------------------------------------------------------------------------------- 1. Andree#1 Armstrong 09/20/01 HBP 12.5% 0% 3.125% 63.281% 2. Kiski Sportsmen#8 Armstrong 04/27/98 HBP 12.5% 0% 3.125% 63.281% 3. Lytle#3 Armstrong 08/28/01 08/28/11 12.5% 0% 3.125% 63.281% 4. Morgan#1 Armstrong 01/22/01 01/22/04 12.5% 0% 3.125% 63.281% 5. Wheatley#5 Armstrong 11/24/97 HBP 12.5% 0% 3.125% 63.281% 6. Bosch#7 Indiana 01/07/99 HBP 12.5% 0% 3.125% 63.281% 7. Cup#1 Indiana 03/31/99 03/31/04 12.5% 0% 3.125% 63.281% 8. Deforno#1 Indiana 04/08/02 10/08/03 12.5% 0% 3.125% 63.281% 9. Lynn#1 Indiana 03/30/99 03/30/04 12.5% 0% 3.125% 63.281% 10. Speranza#4 Indiana 06/16/99 HBP 12.5% 0% 3.125% 63.281% 11. Speranza#9 Indiana 06/16/99 HBP 12.5% 0% 3.125% 63.281% Acres to be Working Net Assigned to Prospect Name Interest Acres the Partnership ----------------------------------------------------------------- 1. Andree#1 75% 130 14.60 2. Kiski Sportsmen#8 75% 170 14.60 3. Lytle#3 75% 150 14.60 4. Morgan#1 75% 98 14.60 5. Wheatley#5 75% 240 14.60 6. Bosch#7 75% 121 14.60 7. Cup#1 75% 145 14.60 8. Deforno#1 75% 77 14.60 9. Lynn#1 75% 80 14.60 10. Speranza#4 75% 150 14.60 11. Speranza#9 75% 150 14.60
- --------------- * HBP - Held by Production (1) U.S. Energy Exploration, originator of the prospect and 25% working interest owner. 46 LOCATION AND PRODUCTION MAP FOR ARMSTRONG AND INDIANA COUNTIES, PENNSYLVANIA 47 [GRAPHIC OMITTED] 48 PRODUCTION DATA FOR ARMSTRONG AND INDIANA COUNTIES, PENNSYLVANIA 49 The Production Data provided in the table below is not intended to imply that the wells to be drilled by the partnership will have the same results, although it is an important indicator in evaluating the economic potential of any well to be drilled by the partnership.
TOTAL MCF THROUGH TOTAL LATEST ID DATE MOS 06/30/03 EXCEPT LOGGERS 30 DAY NUMBER OPERATOR WELL NAME COMPLT'D ON LINE WHERE NOTED DEPTH PROD. 1. 02368 Dominion Peoples Wray, Et. Al. #1 5/3/1921 NA 51,497 / 1992 3096 NA 2. 20128 Dominion Peoples Martin #1 1/14/1958 NA 05,767 / 1992 3134 NA 3. 20154 Dominion Peoples Kerr #1 6/3/1958 NA 03,046 / 1992 3229 NA 4. 20222 Dominion Peoples Deemer #2 2/26/1896 / 12/3/1958 NA 51,637 / 1992 1584/3386 NA 5. 20600 Dominion Peoples Geiger #2 10/10/1963 NA 05,774 / 1992 3457 NA 6. 20768 Dominion Peoples Chambers #2 7/9/1965 NA 43,610 / 1992 3604 NA 7. 20957 Dominion Peoples Chambers #1 3/19/1968 NA 79,140 / 1992 3630 NA 8. 25760 Petroleum Development Corp. (JV USEE) Becker #2 5/8/1998 25 48,880 3510 1890 9. 26070 Petroleum Development Corp. (JV USEE) Egley #1 10/30/00 7 12,800 1240 1830 10. 26078 Petroleum Development Corp. (JV USEE) Kleintop #1 12/20/98 7 10,620 3700 1440 11. 26090 Petroleum Development Corp. (JV USEE) Ott #1 1/19/1999 18 31,000 3580 1650 12. 26091 Petroleum Development Corp. (JV USEE) Becker #3 9/22/1999 10 19,660 3500 1860 13. 26093 Petroleum Development Corp. (JV USEE) Ott #2 9/8/1999 10 18,330 3580 1830 14. 26102 Petroleum Development Corp. (JV USEE) Hollabaugh #1 02/18/99 5 9,760 3620 1890 15. 26108 Petroleum Development Corp. (JV USEE) Wilson #2 3/15/1999 14 19,400 3620 1350 16. 26127 Petroleum Development Corp. (JV USEE) Kiski Sportsmen #2 4/15/1999 14 43,010 3680 2700 17. 26141 Petroleum Development Corp. (JV USEE) Kiski Sportsmen #3 6/23/1999 12 26,940 3893 1920 18. 26157 Petroleum Development Corp. (JV USEE) M. Couch #1 7/10/1999 12 28,440 3710 2160 19. 26172 Petroleum Development Corp. (JV USEE) Ott #4 9/13/1999 10 22,070 3500 2130 20. 26173 Petroleum Development Corp. (JV USEE) Ott #3 9/16/1999 10 16,420 3560 1470 21. 26188 Petroleum Development Corp. (JV USEE) Kiski Sportsmen #4 9/25/1999 10 17,250 3750 1740 22. 26201 Petroleum Development Corp. (JV USEE) Kiski Sportsmen #5 11/21/1999 6 13,300 3734 2040 23. 26208 Petroleum Development Corp. (JV USEE) Walker #1 12/1/1999 6 9,920 4090 1530 24. 26216 Petroleum Development Corp. (JV USEE) Allshouse #1 12/30/1999 7 14,190 3560 1950 25. 26220 Petroleum Development Corp. (JV USEE) Shearer #1 3/4/2000 6 14,580 4068 2280 26. 26221 Petroleum Development Corp. (JV USEE) Shearer #2 3/5/2000 4 7,550 4040 1800
50 The Production Data provided in the table below is not intended to imply that the wells to be drilled by the partnership will have the same results, although it is an important indicator in evaluating the economic potential of any well to be drilled by the partnership.
TOTAL MCF THROUGH TOTAL LATEST ID DATE MOS 06/30/03 EXCEPT LOGGERS 30 DAY NUMBER OPERATOR WELL NAME COMPLT'D ON LINE WHERE NOTED DEPTH PROD. 27. 26222 Petroleum Development Corp. (JV USEE) G. Couch #1 3/10/2000 4 8,160 4070 2040 28. 26224 Petroleum Development Corp. (JV USEE) Walker #4 3/3/2000 4 14,100 4080 2910 29. 26225 Petroleum Development Corp. (JV USEE) Walker #2 3/2/2000 4 9,540 4100 1890 30. 26234 Petroleum Development Corp. (JV USEE) Stankay #1 3/6/2000 4 7,320 4100 1560 31. 26255 Petroleum Development Corp. (JV USEE) Stankay #2 3/7/2000 4 7,900 4098 1680 32. 26374 US Energy Exploration (JV Atlas) Sturiale #1 2/6/2002 15 1,694 3866 93 33. 26426 US Energy Exploration (JV Atlas) Bafik #2 3/9/2002 14 10,509 3904 626 34. 26427 US Energy Exploration (JV Atlas) Canterbury #4 5/8/2001 24 34,049 3696 1218 35. 26431 US Energy Exploration (JV Atlas) Canterbury #8 5/9/2001 24 16,910 3876 724 36. 26437 US Energy Exploration (JV Atlas) Canterbury #12 4/30/2001 24 18,794 3791 409 37. 26438 US Energy Exploration (JV Atlas) Canterbury #13 4/30/2001 24 9,229 3908 178 38. 26439 US Energy Exploration (JV Atlas) Canterbury #15 7/10/2001 22 4,822 3776 154 39. 26440 US Energy Exploration (JV Atlas) Canterbury #17 7/10/2001 22 5,392 3802 327 40. 26442 US Energy Exploration (JV Atlas) Canterbury #20 5/22/2001 23 25,657 3944 1057 41. 26455 US Energy Exploration (JV Atlas) Canterbury #21 10/29/2001 18 16,181 3805 719 42. 26458 US Energy Exploration (JV Atlas) Canterbury #3 5/7/2001 24 12,194 3701 299 43. 26557 US Energy Exploration (JV Atlas) Barr #2 8/9/2001 21 24,906 3868 1116 44. 26558 US Energy Exploration (JV Atlas) Barr #3 8/25/2001 20 34,818 3898 2374 45. 26561 US Energy Exploration (JV Atlas) Schrecengost #2 10/29/2001 18 12,233 3750 383 46. 26562 US Energy Exploration (JV Atlas) Schrecengost #3 11/6/2001 18 11,392 3777 456 47. 26566 US Energy Exploration (JV Atlas) P. White #1 11/16/2001 17 7,230 3950 171 48. 26596 US Energy Exploration (JV Atlas) G. Couch #3 4/24/2002 12 3,908 4053 234 49. 26598 US Energy Exploration (JV Atlas) G. Couch #5 4/24/2002 12 4,506 4355 250 50. 26600 US Energy Exploration (JV Atlas) Dobrosky #2 10/10/2001 19 23,686 3752 1424 51. 26621 US Energy Exploration (JV Atlas) Canterbury #27 10/10/2001 19 31,713 3861 2095 52. 26622 US Energy Exploration (JV Atlas) Canterbury #28 10/10/2001 19 30,075 3814 2927
51 The Production Data provided in the table below is not intended to imply that the wells to be drilled by the partnership will have the same results, although it is an important indicator in evaluating the economic potential of any well to be drilled by the partnership.
TOTAL MCF THROUGH TOTAL LATEST ID DATE MOS 06/30/03 EXCEPT LOGGERS 30 DAY NUMBER OPERATOR WELL NAME COMPLT'D ON LINE WHERE NOTED DEPTH PROD. 53. 26625 US Energy Exploration (JV Atlas) Barr #4 10/18/2001 18 26,266 3804 1215 54. 26627 US Energy Exploration (JV Atlas) Wilson #4 10/10/2001 19 27,553 3802 1754 55. 26663 US Energy Exploration (JV Atlas) Crewe #1 12/31/2001 16 27,831 4058 2163 56. 26669 US Energy Exploration (JV Atlas) R. White #1 11/16/2001 17 5,733 4062 291 57. 26679 US Energy Exploration (JV Atlas) Canterbury #30 1/12/2002 16 22,720 4151 2122 58. 26680 US Energy Exploration (JV Atlas) Canterbury #34 2/18/2002 14 16,389 4220 1339 59. 26681 US Energy Exploration (JV Atlas) Canterbury #31 1/29/2002 15 18,144 4212 1237 60. 26723 US Energy Exploration (JV Atlas) Bernabo #1 1/15/2002 15 6,277 4250 269 61. 26730 US Energy Exploration (JV Atlas) Canterbury #32 7/10/2002 10 10,669 4195 1748 62. 26741 US Energy Exploration (JV Atlas) Crewe #4 8/16/2002 8 17,060 4153 2799 63. 26742 US Energy Exploration (JV Atlas) Musser #1 2/11/2002 15 2,778 4296 126 64. 26743 US Energy Exploration (JV Atlas) Filippini #2 2/2/2002 15 9,432 3882 588 65. 26756 US Energy Exploration (JV Atlas) P. White #4 2/25/2002 14 3,201 4281 152 66. 26758 US Energy Exploration (JV Atlas) Crewe #5 2/12/2002 15 25,548 4156 2705 67. 26788 US Energy Exploration (JV Atlas) Pomfret #1 3/29/2002 13 17,962 3817 1227 68. 26824 US Energy Exploration (JV Atlas) Stankay #5 N/A NA NA 4037 NA 69. 26827 US Energy Exploration (JV Atlas) Boggs #6 1/3/2003 4 5,828 4104 2112 70. 26828 US Energy Exploration (JV Atlas) Boggs #7 9/28/2002 7 13,034 4219 2871 71. 26833 US Energy Exploration (JV Atlas) Boggs #4 8/16/2002 8 9,389 4220 1110 72. 26844 US Energy Exploration (JV Atlas) Filippini #3 1/9/2003 4 5,609 3879 1932 73. 26865 US Energy Exploration (JV Atlas) Rumbaugh #1 11/14/2002 5 4,493 4600 560 74. 26973 US Energy Exploration (JV Atlas) Andree #3 N/A NA NA 4121 NA 75. 27024 US Energy Exploration (JV Atlas) Wheatley #1 N/A NA NA 4211 NA 76. 27040 US Energy Exploration (JV Atlas) Pomfret #2 3/28/2003 1 980 3822 NA 77. 27044 US Energy Exploration (JV Atlas) Rumbaugh #2 3/26/2003 1 911 3808 NA 78. 27126 US Energy Exploration (JV Atlas) Andree #2 N/A NA NA N/A NA
52 The Production Data provided in the table below is not intended to imply that the wells to be drilled by the partnership will have the same results, although it is an important indicator in evaluating the economic potential of any well to be drilled by the partnership.
TOTAL MCF THROUGH TOTAL LATEST ID DATE MOS 06/30/03 EXCEPT LOGGERS 30 DAY NUMBER OPERATOR WELL NAME COMPLT'D ON LINE WHERE NOTED DEPTH PROD. 79. 27127 US Energy Exploration (JV Atlas) Wheatley #3 N/A NA NA 4273 NA 80. 32288 Petroleum Development Corp. (JV USEE) R. Henderson #1 7/1/1999 7 17,230 5213 2400 81. 32418 Petroleum Development Corp. (JV USEE) C. Coleman #1 3/8/2000 4 6,960 4220 1650 82. 32475 Petroleum Development Corp. (JV USEE) C. Coleman #2 3/9/2000 4 7,100 4401 1590 83. 33016 US Energy Exploration (JV Atlas) Henderson #3 5/8/2002 12 14,979 4502 1281 84. 33042 US Energy Exploration (JV Atlas) Rosensteel #5 4/24/2002 12 17,853 4325 1790 85. 33152 US Energy Exploration (JV Atlas) Graham #1 2/12/2003 3 4,477 4336 2407 86. 33155 US Energy Exploration (JV Atlas) Boggs #9 1/31/2003 3 5,261 4393 2171 87. 33157 US Energy Exploration (JV Atlas) Boggs #11 N/A NA NA 4361 NA 88. 33159 US Energy Exploration (JV Atlas) Shearer #4 2/11/2003 3 3,137 4314 1365 89. 33202 US Energy Exploration (JV Atlas) J. Henderson #1 1/15/2003 3 4,458 4456 1553 90. 33273 US Energy Exploration (JV Atlas) Kapusta #2 N/A NA NA 4280 NA 91. 33274 US Energy Exploration (JV Atlas) Bosch #2 N/A NA NA 4392 NA 92. 33288 US Energy Exploration (JV Atlas) Kapusta #1 N/A NA NA N/A NA 93. 33305 US Energy Exploration (JV Atlas) Bosch #4 3/21/2003 1 1,128 4460 NA 94. 33306 US Energy Exploration (JV Atlas) Bosch #5 3/29/2003 1 636 4388 NA 95. 33313 US Energy Exploration (JV Atlas) Speranza #2 N/A NA NA N/A NA
53 UEDC'S GEOLOGIC EVALUATION FOR ARMSTRONG AND INDIANA COUNTIES, PENNSYLVANIA 54 GEOLOGIC EVALUATION ATLAS AMERICA PUBLIC #12-2003 LIMITED PARTNERSHIP Armstrong Prospect Area Pennsylvania Dated: May 6, 2003
Program proposed by: Report submitted by: ATLAS RESOURCES, INC. UEDC 311 Rouser Road United Energy Development Consultants, Inc. P.O. Box 611 1715 Crafton Blvd. Moon Township, PA 15108 Pittsburgh, PA 15205
LOCATION MAP - AREA OF INTEREST [GRAPHIC OMITTED] TABLE OF CONTENTS
LOCATION MAP - AREA OF INTEREST ............................... 1 TABLE OF CONTENTS ............................................. 1 INVESTIGATION SUMMARY ......................................... 2 OBJECTIVE ................................................. 2 AREA OF INVESTIGATION ..................................... 2 METHODOLOGY ............................................... 2 ARMSTRONG PROSPECT AREA ....................................... 2 DRILLING ACTIVITY ......................................... 2 GEOLOGY ................................................... 2 STRATIGRAPHY, LITHOLOGY & DEPOSITION .................. 2 RESERVOIR CHARACTERISTICS ............................. 3 PRODUCTION ................................................ 4 STATEMENTS .................................................... 5 CONCLUSION ................................................ 5 DISCLAIMER ................................................ 5 NON-INTEREST .............................................. 5
55 INVESTIGATION SUMMARY OBJECTIVE The purpose of the following investigation is to evaluate the geologic feasibility and further development of the Armstrong Prospect Area as proposed by Atlas Resources, Inc. ("Atlas"). AREA OF INVESTIGATION A portion of this prospect area, herein identified for drilling in Atlas America Public #12-2003 Limited Partnership, contains acreage in Kiskiminetas Township of Armstrong County and Young and Conemaugh Townships of Indiana County, Pennsylvania. These townships are located in western Pennsylvania. Eleven (11) drilling prospects have currently been designated for this program in the prospect area, which will be targeted to produce natural gas from Upper Devonian reservoirs, found at depths from 1800 feet to 4500 feet beneath the earth's surface. These will be the only prospects evaluated for the purposes of this report. METHODOLOGY Atlas and the in-house archives of UEDC, Inc. provided the data incorporated into this report. Geological mapping and the interpretations by Atlas geologists were also examined. Available "electric" log, completion and production data on "key" wells within and adjacent to the defined prospect area were used to determine productive and depositional trends. ARMSTRONG PROSPECT AREA DRILLING ACTIVITY The proposed drilling area lies within a region of southwestern Pennsylvania, which has seen sporadic activity for more than the past 150 years in terms of exploration for, and exploitation of natural gas reserves. Modern development within and adjacent to the Armstrong Prospect Area has continued steadily since 1950. Over 1500 wells have been drilled in the area during this period. Atlas has entered into a Joint Venture relationship with US Energy Exploration. Located in Rural Valley, Pennsylvania (which is less than 20 miles from the prospect area), US Energy is a local oil and gas producer with more than 15 years experience developing this play and currently operates over 325 wells within and adjacent to the prospect area. US Energy currently maintains an acreage position of over 14,000 acres. Within the prospect, Atlas and its partner adhere to the state regulations for spacing of wells in areas of deep coal mining, which is one thousand (1000) feet in most cases. Atlas continues to identify and extend productive trends. Drilling is ongoing as of the date of this report with recent wells displaying favorable initial drilling and completion results. GEOLOGY STRATIGRAPHY, LITHOLOGY & DEPOSITION In southern Armstrong County the Upper Devonian Bradford Group reservoirs are typically characterized as submarine fan deposits. They are thought to have traveled westward (seaward) down slope from sands deposited out in front of massive deltas throughout Indiana and surrounding counties. The Bradford Group consists of the Lower Warren Sand; Upper and Lower Speechley Sands; Upper, Middle, and Lower Balltown Sands and the First Bradford Sand. [GRAPHIC OMITTED] Stratigraphically, in descending order, the potentially productive units of the Upper Devonian Groups are: 1.) Hundred Foot, 2.) Gordon, 3.) Fifth, 4.) Bayard, 5.) L. Warren, 6.) Upper Speechley, 7.) Lower Speechley, 8.) Upper Balltown, 9.) Middle Balltown, 10.) Lower Balltown, 11.) First Bradford. These stratigraphic relationships are illustrated in the diagram. 56 The Hundred Foot Sand is the shallowest sand of Devonian age encountered in this area. This sand is highly variable in its thickness and porosity development. Often it is in excess of one hundred (100) feet thick with porosities in excess of 18%. Frequently it is accompanied by gas shows and it is used as a gas storage reservoir just to the north of the acreage. Due to its shallow depth and attendant lower pressure this zone is not treated or commingled with the deeper reservoirs found in the play area. However, this zone has the potential for a producible natural completion and is considered a secondary target. The Gordon Sand appears sporadic across the play area and ranges in thickness from nearly ten (10) feet to twenty (20) feet. Porosities range from 6% to about 10%. This sand is considered a secondary target. The Fifth Sand ranges in thickness from a few feet to thirty (30) feet. Porosity values are typically 5% to 12%. This sand is considered a secondary target. The Bayard Sand in the prospect area ranges in thickness from a few feet to more than thirty (30) feet. Porosity values range from 8% to 18% for this sandstone. This sand is also considered a secondary target. The Warren Sands are a primary target when encountered in the prospect area. Typically the lower portion of the Warren interval is better developed. When sand is present in this interval the average thickness ranges from several feet to over thirty (30) feet. Porosities range between 6% and 12% in the area. The Speechley Sands are considered both primary and secondary targets depending on where in the play area they are encountered. Present are an upper and lower sand separated by fifty (50) to seventy-five (75) feet of shale. The upper sand thickness ranges from just a few feet to more than twenty (20) feet and porosity typically ranges from 5% to 12%. Meanwhile the lower sand is usually twenty (20) feet to forty (40) feet thick with porosities that are often between 5% to 12%. The Balltown Sands have limited extent throughout the project area. Generally sand development in the upper portion of the Balltown interval is most favorable and when encountered is typically fifteen (15) feet thick with porosities as high as 20%. This sand is often accompanied by a gas show and is thought to be a significant producer. In areas where this sand is more prevalent it is considered a primary target, but is found sporadically across the play area. Sand development in other portions of this interval are also limited in extent but are treated when encountered. The First Bradford Sand is the primary target in all wells in this immediate area. This sand is present in every well drilled thus far on the acreage. The First Bradford sand will generally range from ten (10) feet in thickness to over thirty-five (35) feet in several distinct trends. Porosities typically range from 8% to 14%. This sand is nearly always accompanied by a gas show. Occasionally, a deeper sand, the Second Bradford sand, develops seventy (70) to one hundred (100) feet below the First Bradford. When warranted, this sand is also completed.. RESERVOIR CHARACTERISTICS Petroleum reservoirs are formed by the presence of an impermeable barrier trapping commercial quantities of natural gas in a more permeable medium. In the Upper Devonian reservoirs, this occurs either stratigraphically when a permeable sand containing hydrocarbons encounters impermeable shale or when permeable sand changes gradually into non-permeable sand by a cementation process known as "diagenesis". Thus, this type of trap represents cemented-in hydrocarbon accumulations. Electric well logs can be used in conjunction with production to interpret reservoir parameters. When sandstones in the Upper Devonian reservoirs develop porosity in excess of 8%, or a bulk density of 2.50 or less, the permeability of the reservoir can become great enough to allow commercial production of natural gas. Small, naturally occurring cracks in the formation, referred to as micro-fractures, can also enhance permeability. A gamma, bulk density, neutron, induction and temperature log suite showing sand development in an Upper Devonian reservoir is illustrated on the following page. 57 [GRAPHIC OMITTED] The temperature log shown in the illustration at left identifies where gas is entering the wellbore. Evidence of a temperature "kick" or cooling is also an indication of enhanced permeability and the willingness of the reservoir to produce natural gas. PRODUCTION The Armstrong prospect area produces from several reservoirs of different age and type. Each well has a unique combination of these reservoirs yielding different production declines. While Atlas anticipates production from each reservoir to be comparable to like reservoirs historically produced throughout the Appalachian Basin, a model decline curve for this prospect area is not included due to the multiple sets of commingled reservoirs exclusively found in this area. 58 STATEMENTS CONCLUSION UEDC has conducted a geologic feasibility study of the drilling area for Atlas America Public #12-2003 Limited Partnership, which will consist of developmental drilling of Upper Devonian reservoirs in Armstrong and Indiana Counties, Pennsylvania. It is the professional opinion of UEDC that the drilling of the eleven (11) wells by Atlas America Public #12-2003 Limited Partnership is supported by sufficient geologic and engineering data. DISCLAIMER For the purpose of this evaluation, UEDC did not visit any leaseholds or inspect any of the associated production equipment. Likewise, UEDC has no knowledge as to the validity of title, liabilities, or corporate matters affecting these properties. UEDC does not warrant individual well performance. NON-INTEREST We hereby confirm that UEDC is an independent consulting firm and that neither this firm or any of it's employees, contract consultants, or officers has, or is committed to acquire any interest, directly or indirectly, in Atlas Resources, Inc.; nor is this firm, or any employee, contract consultant, or officer thereof, otherwise affiliated with Atlas Resources, Inc. We also confirm that neither the employment of, nor payment of compensation received by UEDC in connection with this report, is on a contingent basis. Respectfully submitted, /s/ Robin Anthony -------------------- UEDC, Inc. 59 EXHIBIT (A) FORM OF LIMITED PARTNERSHIP AGREEMENT OF ATLAS AMERICA PUBLIC #12-2003 LIMITED PARTNERSHIP [ATLAS AMERICA PUBLIC #12-2004(___) LIMITED PARTNERSHIP] TABLE OF CONTENTS
Section No. Description Page Section No. Description Page I. FORMATION VII. DURATION, DISSOLUTION, AND WINDING UP 1.01 Formation............................. 1 7.01 Duration.............................. 48 1.02 Certificate of Limited Partnership.... 1 7.02 Dissolution and Winding Up............ 48 1.03 Name, Principal Office and Residence.. 1 1.04 Purpose............................... 1 VIII. MISCELLANEOUS PROVISIONS 8.01 Notices............................... 49 II. DEFINITION OF TERMS 8.02 Time.................................. 50 2.01 Definitions........................... 2 8.03 Applicable Law........................ 50 8.04 Agreement in Counterparts............. 50 III. SUBSCRIPTIONS AND FURTHER CAPITAL 8.05 Amendment............................. 50 CONTRIBUTIONS 8.06 Additional Partners................... 50 3.01 Designation of Managing General 8.07 Legal Effect.......................... 50 Partner and Participants ........... 10 3.02 Participants.......................... 10 EXHIBITS 3.03 Subscriptions to the Partnership...... 11 EXHIBIT (I-A) - 3.04 Capital Contributions of the Managing Form of Managing General Partner Signature Page General Partner....................... 12 EXHIBIT (I-B) - 3.05 Payment of Subscriptions.............. 13 Form of Subscription Agreement 3.06 Partnership Funds..................... 13 EXHIBIT (II) - Form of Drilling and Operating Agreement IV. CONDUCT OF OPERATIONS 4.01 Acquisition of Leases................. 14 4.02 Conduct of Operations................. 16 4.03 General Rights and Obligations of the Participants and Restricted and Prohibited Transactions........... 20 4.04 Designation, Compensation and Removal of Managing General Partner and Removal of Operator............... 30 4.05 Indemnification and Exoneration....... 33 4.06 Other Activities...................... 35 V. PARTICIPATION IN COSTS AND REVENUES, CAPITAL ACCOUNTS, ELECTIONS AND DISTRIBUTIONS 5.01 Participation in Costs and Revenues... 36 5.02 Capital Accounts and Allocations Thereto........................... 39 5.03 Allocation of Income, Deductions and Credits........................... 40 5.04 Elections............................. 42 5.05 Distributions......................... 42 VI. TRANSFER OF INTERESTS 6.01 Transferability....................... 43 6.02 Special Restrictions on Transfers..... 44 6.03 Right of Managing General Partner to Hypothecate and/or Withdraw Its Interests............................. 45 6.04 Presentment........................... 46
i FORM OF LIMITED PARTNERSHIP AGREEMENT OF ATLAS AMERICA PUBLIC #12-2003 LIMITED PARTNERSHIP [ATLAS AMERICA PUBLIC #12-2004(_____) LIMITED PARTNERSHIP] THIS AGREEMENT OF LIMITED PARTNERSHIP ("AGREEMENT"), is made and entered into as of _____________________, 2003, by and among Atlas Resources, Inc., referred to as "Atlas" or the "Managing General Partner," and the remaining parties from time to time signing a Subscription Agreement for Limited Partner Units, these parties sometimes referred to as "Limited Partners," or for Investor General Partner Units, these parties sometimes referred to as "Investor General Partners." ARTICLE I FORMATION 1.01. Formation. Subject to the provisions of this agreement, the parties hereto do hereby form a limited partnership under the Delaware Revised Uniform Limited Partnership Act on the terms and conditions set forth in this Agreement. 1.02. Certificate of Limited Partnership. This document is not only an agreement among the parties, but also may be the Certificate and Agreement of Limited Partnership of the Partnership. This document shall be filed or recorded in the public offices required under applicable law or deemed advisable in the discretion of the Managing General Partner. Amendments to the certificate of limited partnership shall be filed or recorded in the public offices required under applicable law or deemed advisable in the discretion of the Managing General Partner. 1.03. Name, Principal Office and Residence. 1.03(a). Name. The name of the Partnership is Atlas America Public #12-2003 Limited Partnership [Atlas America Public #12-2004(_____) Limited Partnership]. 1.03(b). Residence. The residence of the Managing General Partner is its principal place of business at 311 Rouser Road, Moon Township, Pennsylvania 15108, which shall also serve as the principal place of business of the Partnership. The residence of each Participant shall be as set forth on the Subscription Agreement executed by the Participant. All addresses shall be subject to change on notice to the parties. 1.03(c). Agent for Service of Process. The name and address of the agent for service of process shall be Mr. Jack L. Hollander at Atlas Resources, Inc., 311 Rouser Road, Moon Township, Pennsylvania 15108. 1.04. Purpose. The Partnership shall engage in all phases of the natural gas and oil business. This includes, without limitation, exploration for, development and production of natural gas and oil on the terms and conditions set forth below and any other proper purpose under the Delaware Revised Uniform Limited Partnership Act. The Managing General Partner may not, without the affirmative vote of Participants whose Units equal a majority of the total Units, do the following: (i) change the investment and business purpose of the Partnership; or (ii) cause the Partnership to engage in activities outside the stated business purposes of the Partnership through joint ventures with other entities. 1 ARTICLE II DEFINITION OF TERMS 2.01. Definitions. As used in this Agreement, the following terms shall have the meanings set forth below: 1. "Administrative Costs" means all customary and routine expenses incurred by the Sponsor for the conduct of Partnership administration, including: in-house legal, finance, in-house accounting, secretarial, travel, office rent, telephone, data processing and other items of a similar nature. Administrative Costs shall be limited as follows: (i) no Administrative Costs charged shall be duplicated under any other category of expense or cost; and (ii) no portion of the salaries, benefits, compensation or remuneration of controlling persons of the Managing General Partner shall be reimbursed by the Partnership as Administrative Costs. Controlling persons include directors, executive officers and those holding 5% or more equity interest in the Managing General Partner or a person having power to direct or cause the direction of the Managing General Partner, whether through the ownership of voting securities, by contract, or otherwise. 2. "Administrator" means the official or agency administering the securities laws of a state. 3. "Affiliate" means with respect to a specific person: (i) any person directly or indirectly owning, controlling, or holding with power to vote 10% or more of the outstanding voting securities of the specified person; (ii) any person 10% or more of whose outstanding voting securities are directly or indirectly owned, controlled, or held with power to vote, by the specified person; (iii) any person directly or indirectly controlling, controlled by, or under common control with the specified person; (iv) any officer, director, trustee or partner of the specified person; and (v) if the specified person is an officer, director, trustee or partner, any person for which the person acts in any such capacity. 4. "Agreement" means this Limited Partnership, including all exhibits to this Agreement. 5. "Anthem Securities" means Anthem Securities, Inc., whose principal executive offices are located at 311 Rouser Road, P.O. Box 926, Moon Township, Pennsylvania 15108-0926. 6. "Assessments" means additional amounts of capital which may be mandatorily required of or paid voluntarily by a Participant beyond his subscription commitment. 7. "Atlas" means Atlas Resources, Inc., a Pennsylvania corporation, whose principal executive offices are located at 311 Rouser Road, Moon Township, Pennsylvania 15108. 8. "Capital Account" or "account" means the account established for each party, maintained as provided in ss.5.02 and its subsections. 9. "Capital Contribution" means the amount agreed to be contributed to the Partnership by a Partner pursuant to ss.ss.3.04 and 3.05 and their subsections. 2 10. "Carried Interest" means an equity interest in the Partnership issued to a Person without consideration, in the form of cash or tangible property, in an amount proportionately equivalent to that received from the Participants. 11. "Code" means the Internal Revenue Code of 1986, as amended. 12. "Cost," when used with respect to the sale or transfer of property to the Partnership, means: (i) the sum of the prices paid by the seller or transferor to an unaffiliated person for the property, including bonuses; (ii) title insurance or examination costs, brokers' commissions, filing fees, recording costs, transfer taxes, if any, and like charges in connection with the acquisition of the property; (iii) a pro rata portion of the seller's or transferor's actual necessary and reasonable expenses for seismic and geophysical services; and (iv) rentals and ad valorem taxes paid by the seller or transferor for the property to the date of its transfer to the buyer, interest and points actually incurred on funds used to acquire or maintain the property, and the portion of the seller's or transferor's reasonable, necessary and actual expenses for geological, engineering, drafting, accounting, legal and other like services allocated to the property cost in conformity with generally accepted accounting principles and industry standards, except for expenses in connection with the past drilling of wells which are not producers of sufficient quantities of oil or gas to make commercially reasonable their continued operations, and provided that the expenses enumerated in this subsection (iv) shall have been incurred not more than 36 months before the sale or transfer to the Partnership. "Cost," when used with respect to services, means the reasonable, necessary and actual expense incurred by the seller on behalf of the Partnership in providing the services, determined in accordance with generally accepted accounting principles. As used elsewhere, "Cost" means the price paid by the seller in an arm's-length transaction. 13. "Dealer-Manager" means: (i) Anthem Securities, Inc., an Affiliate of the Managing General Partner, the broker/dealer which will manage the offering and sale of the Units in all states other than Minnesota and New Hampshire; and (ii) Bryan Funding, Inc., the broker/dealer which will manage the offering and sale of Units in Minnesota and New Hampshire. 14. "Development Well" means a well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic Horizon known to be productive. 15. "Direct Costs" means all actual and necessary costs directly incurred for the benefit of the Partnership and generally attributable to the goods and services provided to the Partnership by parties other than the Sponsor or its Affiliates. Direct Costs: (i) may not include any cost otherwise classified as Organization and Offering Costs, Administrative Costs, Intangible Drilling Costs, Tangible Costs, Operating Costs or costs related to the Leases; but 3 (ii) may include the cost of services provided by the Sponsor or its Affiliates if the services are provided pursuant to written contracts and in compliance with ss.4.03(d)(7) or pursuant to the Managing General Partner's role as Tax Matters Partner. 16. "Distribution Interest" means an undivided interest in the Partnership's assets after payments to the Partnership's creditors or the creation of a reasonable reserve therefor, in the ratio the positive balance of a party's Capital Account bears to the aggregate positive balance of the Capital Accounts of all of the parties determined after taking into account all Capital Account adjustments for the taxable year during which liquidation occurs (other than those made pursuant to liquidating distributions or restoration of deficit Capital Account balances). Provided, however, after the Capital Accounts of all of the parties have been reduced to zero, the interest in the remaining Partnership assets shall equal a party's interest in the related Partnership revenues as set forth in ss.5.01 and its subsections of this Agreement. 17. "Drilling and Operating Agreement" means the proposed Drilling and Operating Agreement between the Managing General Partner or an Affiliate as Operator, and the Partnership as Developer, a copy of the proposed form of which is attached to this Agreement as Exhibit (II). 18. "Exploratory Well" means a well drilled to: (i) find commercially productive hydrocarbons in an unproved area; (ii) find a new commercially productive Horizon in a field previously found to be productive of hydrocarbons at another Horizon; or (iii) significantly extend a known prospect. 19. "Farmout" means an agreement by the owner of the leasehold or Working Interest to assign his interest in certain acreage or well to the assignees, retaining some interest such as an Overriding Royalty Interest, an oil and gas payment, offset acreage or other type of interest, subject to the drilling of one or more specific wells or other performance as a condition of the assignment. 20. "Final Terminating Event" means any one of the following: (i) the expiration of the Partnership's fixed term; (ii) notice to the Participants by the Managing General Partner of its election to terminate the Partnership's affairs; (iii) notice by the Participants to the Managing General Partner of their similar election through the affirmative vote of Participants whose Units equal a majority of the total Units; or (iv) the termination of the Partnership under ss.708(b)(1)(A) of the Code or the Partnership ceases to be a going concern. 21. "Horizon" means a zone of a particular formation; that part of a formation of sufficient porosity and permeability to form a petroleum reservoir. 22. "Independent Expert" means a person with no material relationship to the Sponsor or its Affiliates who is qualified and in the business of rendering opinions regarding the value of natural gas and oil properties based on the evaluation of all pertinent economic, financial, geologic and engineering information available to the Sponsor or its Affiliates. 23. "Initial Closing Date" means the date after the minimum amount of subscription proceeds has been received when subscription proceeds are first withdrawn from the escrow account. 4 24. "Intangible Drilling Costs" or "Non-Capital Expenditures" means those expenditures associated with property acquisition and the drilling and completion of natural gas and oil wells that under present law are generally accepted as fully deductible currently for federal income tax purposes. This includes all expenditures made for any well before production in commercial quantities for wages, fuel, repairs, hauling, supplies and other costs and expenses incident to and necessary for drilling the well and preparing the well for production of natural gas or oil, that are currently deductible pursuant to Section 263(c) of the Code and Treasury Reg. Section 1.612-4, and are generally termed "intangible drilling and development costs," including the expense of plugging and abandoning any well before a completion attempt. 25. "Interim Closing Date" means those date(s) after the Initial Closing Date, but before the Offering Termination Date, that the Managing General Partner, in its sole discretion, applies additional subscription proceeds to additional Partnership activities, including drilling activities. 26. "Investor General Partners" means: (i) the persons signing the Subscription Agreement as Investor General Partners; and (ii) the Managing General Partner to the extent of any optional subscription under ss.3.03(b)(2). All Investor General Partners shall be of the same class and have the same rights. 27. "Landowner's Royalty Interest" means an interest in production, or its proceeds, to be received free and clear of all costs of development, operation, or maintenance, reserved by a landowner on the creation of a Lease. 28. "Leases" means full or partial interests in natural gas and oil leases, oil and natural gas mineral rights, fee rights, licenses, concessions, or other rights under which the holder is entitled to explore for and produce oil and/or natural gas, and includes any contractual rights to acquire any such interest. 29. "Limited Partners" means: (i) the persons signing the Subscription Agreement as Limited Partners; (ii) the Managing General Partner to the extent of any optional subscription under ss.3.03(b)(2); (iii) the Investor General Partners on the conversion of their Investor General Partner Units to Limited Partner Units pursuant to ss.6.01(b); and (iv) any other persons who are admitted to the Partnership as additional or substituted Limited Partners. Except as provided in ss.3.05(b), with respect to the required additional Capital Contributions of Investor General Partners, all Limited Partners shall be of the same class and have the same rights. 30. "Managing General Partner" means: (i) Atlas Resources, Inc.; or (ii) any Person admitted to the Partnership as a general partner other than as an Investor General Partner who is designated to exclusively supervise and manage the operations of the Partnership. 31. "Managing General Partner Signature Page" means an execution and subscription instrument in the form attached as Exhibit (I- A) to this Agreement, which is incorporated in this Agreement by reference. 5 32. "Offering Termination Date" means the date after the minimum amount of subscription proceeds has been received on which the Managing General Partner determines, in its sole discretion, the Partnership's subscription period is closed and the acceptance of subscriptions ceases, which shall not be later than December 31, 2003 [December 31, 2004 with respect to Partnerships designated "Atlas America Public #12-2004(_) Limited Partnership."] 33. "Operating Costs" means expenditures made and costs incurred in producing and marketing natural gas or oil from completed wells. These costs include, but are not limited to: (i) labor, fuel, repairs, hauling, materials, supplies, utility charges and other costs incident to or related to producing and marketing natural gas and oil; (ii) ad valorem and severance taxes; (iii) insurance and casualty loss expense; and (iv) compensation to well operators or others for services rendered in conducting these operations. Operating Costs also include reworking, workover, subsequent equipping, and similar expenses relating to any well. 34. "Operator" means the Managing General Partner, as operator of Partnership Wells in Pennsylvania, and the Managing General Partner or an Affiliate as Operator of Partnership Wells in other areas of the United States. 35. "Organization and Offering Costs" means all costs of organizing and selling the offering including, but not limited to: (i) total underwriting and brokerage discounts and commissions (including fees of the underwriters' attorneys); (ii) expenses for printing, engraving, mailing, salaries of employees while engaged in sales activities, charges of transfer agents, registrars, trustees, escrow holders, depositaries, engineers and other experts; (iii) expenses of qualification of the sale of the securities under federal and state law, including taxes and fees, accountants' and attorneys' fees; and (iv) other front-end fees. Organization and Offering Costs also includes the 2.5% Dealer- Manager fee, a 7% Sales Commission, a .5% accountable marketing expense fee, and a .5% reimbursement of the Selling Agents' bona fide accountable due diligence expenses payable to the Dealer-Manager. 36. "Organization Costs" means all costs of organizing the offering including, but not limited to: (i) expenses for printing, engraving, mailing, salaries of employees while engaged in sales activities, charges of transfer agents, registrars, trustees, escrow holders, depositaries, engineers and other experts; (ii) expenses of qualification of the sale of the securities under federal and state law, including taxes and fees, accountants' and attorneys' fees; and (iii) other front-end fees. 6 37. "Overriding Royalty Interest" means an interest in the natural gas and oil produced under a Lease, or the proceeds from the sale thereof, carved out of the Working Interest, to be received free and clear of all costs of development, operation, or maintenance. 38. "Participants" means: (i) the Managing General Partner to the extent of its optional subscription under ss.3.03(b)(2); (ii) the Limited Partners; and (iii) the Investor General Partners. 39. "Partners" means: (i) the Managing General Partner; (ii) the Investor General Partners; and (iii) the Limited Partners. 40. "Partnership" means Atlas America Public #12-2003 Limited Partnership. [Atlas America Public #12-2004 (_____) Limited Partnership]. 41. "Partnership Net Production Revenues" means gross revenues after deduction of the related Operating Costs, Direct Costs, Administrative Costs and all other Partnership costs not specifically allocated. 42. "Partnership Well" means a well, some portion of the revenues from which is received by the Partnership. 43. "Person" means a natural person, partnership, corporation, association, trust or other legal entity. 44. "Production Purchase" or "Income" Program means any program whose investment objective is to directly acquire, hold, operate, and/or dispose of producing oil and gas properties. Such a program may acquire any type of ownership interest in a producing property, including, but not limited to, working interests, royalties, or production payments. A program which spends at least 90% of capital contributions and funds borrowed (excluding offering and organizational expenses) in the above described activities is presumed to be a production purchase or income program. 45. "Program" means one or more limited or general partnerships or other investment vehicles formed, or to be formed, for the primary purpose of: (i) exploring for natural gas, oil and other hydrocarbon substances; or (ii) investing in or holding any property interests which permit the exploration for or production of hydrocarbons or the receipt of such production or its proceeds. 46. "Prospect" means an area covering lands which are believed by the Managing General Partner to contain subsurface structural or stratigraphic conditions making it susceptible to the accumulations of hydrocarbons in commercially productive quantities at one or more Horizons. The area, which may be different for different Horizons, shall be: (i) designated by the Managing General Partner in writing before the conduct of Partnership operations; and 7 (ii) enlarged or contracted from time to time on the basis of subsequently acquired information to define the anticipated limits of the associated hydrocarbon reserves and to include all acreage encompassed therein. If the well to be drilled by the Partnership is to a Horizon containing Proved Reserves, then a "Prospect" for a particular Horizon may be limited to the minimum area permitted by state law or local practice, whichever is applicable, to protect against drainage from adjacent wells. Subject to the foregoing sentence, "Prospect" shall be deemed the drilling or spacing unit for the Clinton/Medina geological formation and the Mississippian and/or Upper Devonian Sandstone reservoirs in Ohio, Pennsylvania, and New York. 47. "Proved Developed Oil and Gas Reserves" means reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as "proved developed reserves" only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved. 48. "Proved Reserves" means the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. (i) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes: (a) that portion delineated by drilling and defined by gas- oil and/or oil-water contacts, if any; and (b) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir. (ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the "proved" classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based. (iii) Estimates of proved reserves do not include the following: (a) oil that may become available from known reservoirs but is classified separately as "indicated additional reserves"; (b) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (c) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and (d) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources. 8 49. "Proved Undeveloped Reserves" means reserves that are expected to be recovered from either: (i) new wells on undrilled acreage; or (ii) from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir. 50. "Roll-Up" means a transaction involving the acquisition, merger, conversion or consolidation, either directly or indirectly, of the Partnership and the issuance of securities of a Roll-Up Entity. The term does not include: (i) a transaction involving securities of the Partnership that have been listed for at least 12 months on a national exchange or traded through the National Association of Securities Dealers Automated Quotation National Market System; or (ii) a transaction involving the conversion to corporate, trust or association form of only the Partnership if, as a consequence of the transaction, there will be no significant adverse change in any of the following: (a) voting rights; (b) the Partnership's term of existence; (c) the Managing General Partner's compensation; and (d) the Partnership's investment objectives. 51. "Roll-Up Entity" means a partnership, trust, corporation or other entity that would be created or survive after the successful completion of a proposed roll-up transaction. 52. "Sales Commissions" means all underwriting and brokerage discounts and commissions incurred in the sale of Units payable to registered broker/ dealers, but excluding the Dealer-Manager fee, a .5% accountable marketing expense fee, and a .5% reimbursement for bona fide accountable due diligence expenses. 53. "Selling Agents" means those broker/dealers selected by the Dealer- Manager which will participate in the offer and sale of the Units. 54. "Sponsor" means any person directly or indirectly instrumental in organizing, wholly or in part, a program or any person who will manage or is entitled to manage or participate in the management or control of a program. The definition includes: (i) the managing and controlling general partner(s) and any other person who actually controls or selects the person who controls 25% or more of the exploratory, development or producing activities of the program, or any segment thereof, even if that person has not entered into a contract at the time of formation of the program; and 9 (ii) whenever the context so requires, the term "sponsor" shall be deemed to include its affiliates. "Sponsor" does not include wholly independent third-parties such as attorneys, accountants, and underwriters whose only compensation is for professional services rendered in connection with the offering of units. 55. "Subscription Agreement" means an execution and subscription instrument in the form attached as Exhibit (I-B) to this Agreement, which is incorporated in this Agreement by reference. 56. "Tangible Costs" or "Capital Expenditures" means those costs associated with drilling and completing natural gas and oil wells which are generally accepted as capital expenditures under the Code. This includes all of the following: (i) costs of equipment, parts and items of hardware used in drilling and completing a well; and (ii) those items necessary to deliver acceptable natural gas and oil production to purchasers to the extent installed downstream from the wellhead of any well and which are required to be capitalized under the Code and its regulations. 57. "Tax Matters Partner" means the Managing General Partner. 58. "Units" or "Units of Participation" means up to 375 Limited Partner interests and up to 7,125 Investor General Partner interests purchased by Participants in the Partnership under the provisions of ss.3.03 and its subsections, including any rights to profits, losses, income, gain, credits, deductions, cash distributions or returns of capital or other attributes of the Units. 59. "Working Interest" means an interest in a Lease which is subject to some portion of the cost of development, operation, or maintenance of the Lease. ARTICLE III SUBSCRIPTIONS AND FURTHER CAPITAL CONTRIBUTIONS 3.01. Designation of Managing General Partner and Participants. Atlas shall serve as Managing General Partner of the Partnership. Atlas shall further serve as a Participant to the extent of any subscription made by it pursuant to ss.3.03(b)(2). Limited Partners and Investor General Partners, including Affiliates of the Managing General Partner, shall serve as Participants. 3.02. Participants. 3.02(a). Limited Partner at Formation. Atlas America, Inc., as Original Limited Partner, has acquired one Unit and has made a Capital Contribution of $100. On the admission of one or more Limited Partners, the Partnership shall return to the Original Limited Partner its Capital Contribution and shall reacquire its Unit. The Original Limited Partner shall then cease to be a Limited Partner in the Partnership with respect to the Unit. 3.02(b). Offering of Interests. The Partnership is authorized to admit to the Partnership at the Initial Closing Date, any Interim Closing Date(s), and the Offering Termination Date additional Participants whose Subscription Agreements are accepted by the Managing General Partner if, after the admission of the additional Participants, the total Units do not exceed the maximum number of Units set forth in ss.3.03(c)(1). 10 3.02(c). Admission of Participants. No action or consent by the Participants shall be required for the admission of additional Participants pursuant to this Agreement. All subscribers' funds shall be held by an independent interest bearing escrow holder and shall not be released to the Partnership until the receipt of the minimum amount of subscription proceeds set forth in ss.3.03(c)(2). Thereafter, subscriptions may be paid directly to the Partnership account. 3.03. Subscriptions to the Partnership. 3.03(a). Subscriptions by Participants. 3.03(a)(1). Subscription Price and Minimum Subscription. The subscription price of a Unit in the Partnership shall be $10,000, except as set forth below, and shall be designated on each Participant's Subscription Agreement and payable as set forth in Section 3.05(b)(1). The minimum subscription per Participant shall be one Unit ($10,000); however, the Managing General Partner, in its discretion, may accept one-half Unit ($5,000) subscriptions. Larger subscriptions shall be accepted in $1,000 increments, beginning with $6,000, $7,000, etc. Notwithstanding the foregoing, the subscription price for: (i) the Managing General Partner, its officers, directors, and Affiliates, and Participants who buy Units through the officers and directors of the Managing General Partner, shall be reduced by an amount equal to the 2.5% Dealer-Manager fee, the 7% Sales Commission, the .5% accountable marketing expense fee, and the .5% reimbursement of the Selling Agents' bona fide accountable due diligence expenses, which shall not be paid with respect to these sales; and (ii) the subscription price for Registered Investment Advisors and their clients, and Selling Agents and their registered representatives and principals, shall be reduced by an amount equal to the 7% Sales Commission, which shall not be paid with respect to these sales. No more than 5% of the total Units shall be sold with the discounts described above. 3.03(a)(2). Effect of Subscription. Execution of a Subscription Agreement shall serve as an agreement by the Participant to be bound by each and every term of this Agreement. 3.03(b). Subscriptions by Managing General Partner. 3.03(b)(1). Managing General Partner's Required Subscription. The Managing General Partner, as a general partner and not as a Participant, shall: (i) contribute to the Partnership the Leases which will be drilled by the Partnership on the terms set forth in ss.4.01(a)(4); and (ii) pay the costs or make the required contributions charged to it under this Agreement. These Capital Contributions shall be paid or made by the Managing General Partner at the time the costs are required to be paid by the Partnership, but no later than December 31, 2004 [December 31, 2005]. 3.03(b)(2). Managing General Partner's Optional Additional Subscription. In addition to the Managing General Partner's required subscription under ss.3.03(b)(1), the Managing General Partner may subscribe to up to 10% of the Units under the provisions of ss.3.03(a) and its subsections, and, subject to the limitations on voting rights set forth in ss.4.03(c)(3), to that extent shall be deemed a Participant in the Partnership for all purposes under this Agreement. 3.03(b)(3). Effect of and Evidencing Subscription. The Managing General Partner has executed a Managing General Partner Signature Page which: 11 (i) evidences the Managing General Partner's required subscription under ss.3.03(b)(1); and (ii) may be amended to reflect the amount of any optional subscription under ss.3.03(b)(2). Execution of the Managing General Partner Signature Page serves as an agreement by the Managing General Partner to be bound by each and every term of this Agreement. 3.03(c). Maximum and Minimum Number of Units. 3.03(c)(1). Maximum Number of Units. The maximum number of Units may not exceed 7,500 Units, which is up to $75,000,000 of cash subscription proceeds excluding the subscription discounts permitted under ss.3.03(a)(1). Notwithstanding the foregoing, the maximum number of Units in all partnerships in Atlas America Public #12-2003 Program, in the aggregate, shall not exceed 7,500 Units which is up to $75,000,000 of cash subscription proceeds excluding the subscription discounts permitted under ss.3.03(a)(1). 3.03(c)(2). Minimum Number of Units. The minimum number of Units shall equal at least 100 Units, but in any event not less than that number of Units which provides the Partnership with cash subscription proceeds of $1,000,000, excluding the subscription discounts permitted under ss.3.03(a)(1). If at the Offering Termination Date the minimum number of Units has not been received and accepted, then all monies deposited by subscribers shall be promptly returned to them. They shall receive interest earned on their subscription proceeds from the date the monies were deposited in escrow through the date of refund. The partnership may break escrow and begin its drilling activities in the Managing General Partner's sole discretion on receipt of the minimum subscriptions. 3.03(d). Acceptance of Subscriptions. 3.03(d)(1). Discretion by the Managing General Partner. Acceptance of subscriptions is discretionary with the Managing General Partner. The Managing General Partner may reject any subscription for any reason it deems appropriate. 3.03(d)(2). Time Period in Which to Accept Subscriptions. Subscriptions shall be accepted or rejected by the Partnership within 30 days of their receipt. If a subscription is rejected, then all funds shall be returned to the subscriber promptly. 3.03(d)(3) Admission to the Partnership. The Participants shall be admitted to the Partnership as follows: (i) not later than 15 days after the release from escrow of Participants' funds to the Partnership; and (ii) after the close of the escrow account not later than the last day of the calendar month in which their Subscription Agreements were accepted by the Partnership. 3.04. Capital Contributions of the Managing General Partner. 3.04(a). Minimum Amount of Managing General Partner's Required Contribution. The Managing General Partner is required to: (i) make aggregate Capital Contributions to the Partnership, including Leases contributed under ss.3.03(b)(1)(i), of not less than 25% of all Capital Contributions to the Partnership; and (ii) maintain a minimum Capital Account balance equal to not less than 1% of total positive Capital Account balances for the Partnership. 3.04(b). On Liquidation the Managing General Partner Must Contribute Deficit Balance in Its Capital Account. The Managing General Partner shall contribute to the Partnership any deficit balance in its Capital Account on the occurrence of either of the following events: 12 (i) the liquidation of the Partnership; or (ii) the liquidation of the Managing General Partner's interest in the Partnership. This shall be determined after taking into account all adjustments for the Partnership's taxable year during which the liquidation occurs, other than adjustments made pursuant to this requirement, by the end of the taxable year in which its interest in the Partnership is liquidated or, if later, within 90 days after the date of the liquidation. 3.04(c). Interest for Contributions. The interest of the Managing General Partner in the capital and revenues of the Partnership is in consideration for, and is the only consideration for, its Capital Contribution to the Partnership. 3.05. Payment of Subscriptions. 3.05(a). Managing General Partner's Subscriptions. The Managing General Partner shall pay any optional subscription under ss.3.03(b)(2) in the same manner as the Participants. 3.05(b). Participant Subscriptions and Additional Capital Contributions of the Investor General Partners. 3.05(b)(1). Payment of Subscription Agreements. A Participant shall pay the amount designated as the subscription price on the Subscription Agreement executed by the Participant 100% in cash at the time of subscribing. A Participant shall receive interest on the amount he pays from the time his subscription proceeds are deposited in the escrow account, or the Partnership account after the minimum number of Units have been received as provided in ss.3.06(b), up until the Offering Termination Date. 3.05(b)(2). Additional Required Capital Contributions of the Investor General Partners. Investor General Partners must make Capital Contributions to the Partnership when called by the Managing General Partner, in addition to their subscriptions, for their pro rata share of any Partnership obligations and liabilities which are recourse to the Investor General Partners and are represented by their ownership of Units before the conversion of Investor General Units to Limited Partner Units under ss.6.01(b). 3.05(b)(3). Default Provisions. The failure of an Investor General Partner to timely make a required additional Capital Contribution under this section results in his personal liability to the other Investor General Partners for the amount in default. The remaining Investor General Partners, pro rata, must pay the defaulting Investor General Partner's share of Partnership liabilities and obligations. In that event, the remaining Investor General Partners: (i) shall have a first and preferred lien on the defaulting Investor General Partner's interest in the Partnership to secure payment of the amount in default plus interest at the legal rate; (ii) shall be entitled to receive 100% of the defaulting Investor General Partner's cash distributions directly from the Partnership until the amount in default is recovered in full plus interest at the legal rate; and (iii) may commence legal action to collect the amount due plus interest at the legal rate. 3.06. Partnership Funds. 3.06(a). Fiduciary Duty. The Managing General Partner has a fiduciary responsibility for the safekeeping and use of all funds and assets of the Partnership, whether or not in the Managing General Partner's possession or control. The Managing General Partner shall not employ, or permit another to employ, the funds and assets in any manner except for the exclusive benefit of the Partnership. Neither this Agreement nor any other agreement between the Managing General Partner and the Partnership shall contractually limit any fiduciary duty owed to the Participants by the Managing General Partner under applicable law, except as provided in ss.ss.4.01, 4.02, 4.04, 4.05 and 4.06 of this Agreement. 13 3.06(b). Special Account After the Receipt of the Minimum Partnership Subscriptions. Following the receipt of the minimum number of Units and breaking escrow, the funds of the Partnership shall be held in a separate interest-bearing account maintained for the Partnership and shall not be commingled with funds of any other entity. 3.06(c). Investment. 3.06(c)(1). Investments in Other Entities. Partnership funds may not be invested in the securities of another person except in the following instances: (i) investments in Working Interests or undivided Lease interests made in the ordinary course of the Partnership's business; (ii) temporary investments made as set forth in ss.3.06(c)(2); (iii) multi-tier arrangements meeting the requirements of ss.4.03(d)(15); (iv) investments involving less than 5% of the Partnership's subscription proceeds which are a necessary and incidental part of a property acquisition transaction; and (v) investments in entities established solely to limit the Partnership's liabilities associated with the ownership or operation of property or equipment, provided that duplicative fees and expenses shall be prohibited. 3.06(c)(2). Permissible Investments Before Investment in Partnership Activities. After the Initial Closing Date and until proceeds from the offering are invested in the Partnership's operations, the proceeds may be temporarily invested in income producing short-term, highly liquid investments, in which there is appropriate safety of principal, such as U.S. Treasury Bills. ARTICLE IV CONDUCT OF OPERATIONS 4.01. Acquisition of Leases. 4.01(a). Assignment to Partnership. 4.01(a)(1). In General. The Managing General Partner shall select, acquire and assign or cause to have assigned to the Partnership full or partial interests in Leases, by any method customary in the natural gas and oil industry, subject to the terms and conditions set forth below. The Partnership and other partnerships in Atlas America Public #12-2003 Program may acquire and develop interests in Leases covering one or more of the same Prospects, in the Managing General Partner's discretion. The Partnership shall acquire only Leases reasonably expected to meet the stated purposes of the Partnership. No Leases shall be acquired for the purpose of a subsequent sale, Farmout, or other disposition unless the acquisition is made after a well has been drilled to a depth sufficient to indicate that the acquisition would be in the Partnership's best interest. 4.01(a)(2). Federal and State Leases. The Partnership is authorized to acquire Leases on federal and state lands. 4.01(a)(3). Managing General Partner's Discretion as to Terms and Burdens of Acquisition. Subject to the provisions of ss.4.03(d) and its subsections, the acquisitions of Leases or other property may be made under any terms and obligations, including: (i) any limitations as to the Horizons to be assigned to the Partnership; and (ii) subject to any burdens as the Managing General Partner deems necessary in its sole discretion. 4.01(a)(4). Cost of Leases. All Leases shall be: 14 (i) contributed to the Partnership by the Managing General Partner or its Affiliates other than an affiliated program; and (ii) credited towards the Managing General Partner's required Capital Contribution set forth in ss.3.03(b)(1) at the Cost of the Lease, unless the Managing General Partner has cause to believe that Cost is materially more than the fair market value of the property, in which case the credit for the contribution must be made at a price not in excess of the fair market value. A determination of fair market value must be: (i) supported by an appraisal from an Independent Expert; and (ii) maintained in the Partnership's records for six years along with associated supporting information. 4.01(a)(5). The Managing General Partner, Operator or Their Affiliates' Rights in the Remainder Interests. Subject to the provisions of ss.4.03(d) and its subsections, to the extent the Partnership does not acquire a full interest in a Lease from the Managing General Partner or its Affiliates, the remainder of the interest in the Lease may be held by the Managing General Partner or its Affiliates. They may either: (i) retain and exploit the remaining interest for their own account; or (ii) sell or otherwise dispose of all or a part of the remaining interest. Profits from the exploitation and/or disposition of their retained interests in the Leases shall be for the benefit of the Managing General Partner or its Affiliates to the exclusion of the Partnership. 4.01(a)(6). No Breach of Duty. Subject to the provisions of ss.4.03 and its subsections, acquisition of Leases from the Managing General Partner, the Operator or their Affiliates shall not be considered a breach of any obligation owed by them to the Partnership or the Participants. 4.01(b). No Overriding Royalty Interests. Neither the Managing General Partner, the Operator nor any Affiliate shall retain any Overriding Royalty Interest on the Leases acquired by the Partnership. 4.01(c). Title and Nominee Arrangements. 4.01(c)(1). Legal Title. Legal title to all Leases acquired by the Partnership shall be held on a permanent basis in the name of the Partnership. However, Partnership properties may be held temporarily in the name of: (i) the Managing General Partner; (ii) the Operator; (iii) their Affiliates; or (iv) in the name of any nominee designated by the Managing General Partner to facilitate the acquisition of the properties. 4.01(c)(2). Managing General Partner's Discretion. The Managing General Partner shall take the steps which are necessary in its best judgment to render title to the Leases to be acquired by the Partnership acceptable for the purposes of the Partnership. The Managing General Partner shall be free, however, to use its own best judgment in waiving title requirements. The Managing General Partner shall not be liable to the Partnership or to the other parties for any mistakes of judgment; nor shall the Managing General Partner be deemed to be making any warranties or representations, express or implied, as to the validity or merchantability of the title to the Leases assigned to the Partnership or the extent of the interest covered thereby except as otherwise provided in the Drilling and Operating Agreement. 15 4.01(c)(3). Commencement of Operations. The Partnership shall not begin operations on the Leases acquired by the Partnership unless the Managing General Partner is satisfied that necessary title requirements have been satisfied. 4.02. Conduct of Operations. 4.02(a). In General. The Managing General Partner shall establish a program of operations for the Partnership. Subject to the limitations contained in Article III of this Agreement concerning the maximum Capital Contribution which can be required of a Limited Partner, the Managing General Partner, the Limited Partners, and the Investor General Partners agree to participate in the program so established by the Managing General Partner. 4.02(b). Management. Subject to any restrictions contained in this Agreement, the Managing General Partner shall exercise full control over all operations of the Partnership. 4.02(c). General Powers of the Managing General Partner. 4.02(c)(1). In General. Subject to the provisions of 14.03 and its subsections, and to any authority which may be granted the Operator under ss.4.02(c)(3)(b), the Managing General Partner shall have full authority to do all things deemed necessary or desirable by it in the conduct of the business of the Partnership. Without limiting the generality of the foregoing, the Managing General Partner is expressly authorized to engage in: (i) the making of all determinations of which Leases, wells and operations will be participated in by the Partnership, which includes: (a) which Leases are developed; (b) which Leases are abandoned; or (c) which leases are sold or assigned to other parties, including other investor ventures organized by the Managing General Partner, the Operator, or any of their Affiliates; (ii) the negotiation and execution on any terms deemed desirable in its sole discretion of any contracts, conveyances, or other instruments, considered useful to the conduct of the operations or the implementation of the powers granted it under this Agreement, including, without limitation: (a) the making of agreements for the conduct of operations, including agreements and financial instruments relating to hedging the Partnership's natural gas and oil; (b) the exercise of any options, elections, or decisions under any such agreements; and (c) the furnishing of equipment, facilities, supplies and material, services, and personnel; (iii) the exercise, on behalf of the Partnership or the parties, as the Managing General Partner in its sole judgment deems best, of all rights, elections and options granted or imposed by any agreement, statute, rule, regulation, or order; (iv) the making of all decisions concerning the desirability of payment, and the payment or supervision of the payment, of all delay rentals and shut-in and minimum or advance royalty payments; (v) the selection of full or part-time employees and outside consultants and contractors and the determination of their compensation and other terms of employment or hiring; (vi) the maintenance of insurance for the benefit of the Partnership and the parties as it deems necessary, but in no event less in amount or type than the following: (a) worker's compensation insurance in full compliance with the laws of the Commonwealth of Pennsylvania and any other applicable state laws; 16 (b) liability insurance, including automobile, which has a $1,000,000 combined single limit for bodily injury and property damage in any one accident or occurrence and in the aggregate; and (c) liability and excess liability insurance as to bodily injury and property damage with combined limits of $50,000,000 during drilling operations and thereafter, per occurrence or accident and in the aggregate, which includes $1,000,000 of seepage, pollution and contamination insurance which protects and defends the insured against property damage or bodily injury claims from third-parties, other than a co-owner of the Working Interest, alleging seepage, pollution or contamination damage resulting from a pollution incident. The excess liability insurance shall be in place and effective no later than the date drilling operations begin, and the Partnership shall have the benefit of the Managing General Partner's $50,000,000 liability insurance on the same basis as the Managing General Partner and its Affiliates, including the Managing General Partner's other Programs; (vii) the use of the funds and revenues of the Partnership, and the borrowing on behalf of, and the loan of money to, the Partnership, on any terms it sees fit, for any purpose, including without limitation: (a) the conduct or financing, in whole or in part, of the drilling and other activities of the Partnership; (b) the conduct of additional operations; and (c) the repayment of any borrowings or loans used initially to finance these operations or activities; (viii) the disposition, hypothecation, sale, exchange, release, surrender, reassignment or abandonment of any or all assets of the Partnership, including without limitation, the Leases, wells, equipment and production therefrom, provided that the sale of all or substantially all of the assets of the Partnership shall only be made as provided in ss.4.03(d)(6); (ix) the formation of any further limited or general partnership, tax partnership, joint venture, or other relationship which it deems desirable with any parties who it, in its sole and absolute discretion, selects, including any of its Affiliates; (x) the control of any matters affecting the rights and obligations of the Partnership, including: (a) the employment of attorneys to advise and otherwise represent the Partnership; (b) the conduct of litigation and other incurring of legal expense; and (c) the settlement of claims and litigation; (xi) the operation of producing wells drilled on the Leases or on a Prospect which includes any part of the Leases; (xii) the exercise of the rights granted to it under the power of attorney created under this Agreement; and (xiii) the incurring of all costs and the making of all expenditures in any way related to any of the foregoing. 4.02(c)(2). Scope of Powers. The Managing General Partner's powers shall extend to any operation participated in by the Partnership or affecting its Leases, or other property or assets, irrespective of whether or not the Managing General Partner is designated operator of the operation by any outside persons participating therein. 4.02(c)(3). Delegation of Authority. 4.02(c)(3)(a). In General. The Managing General Partner may subcontract and delegate all or any part of its duties under this Agreement to any entity chosen by it, including an entity related to it. The party shall have the same powers in the conduct of the duties as would the Managing General Partner. The delegation, however, shall not relieve the Managing General Partner of its responsibilities under this Agreement. 17 4.02(c)(3)(b). Delegation to Operator. The Managing General Partner is specifically authorized to delegate any or all of its duties to the Operator by executing the Drilling and Operating Agreement. This delegation shall not relieve the Managing General Partner of its responsibilities under this Agreement. In no event shall any consideration received for operator services be in excess of competitive rates or duplicative of any consideration or reimbursements received under this Agreement. The Managing General Partner may not benefit by interpositioning itself between the Partnership and the actual provider of operator services. 4.02(c)(4). Related Party Transactions. Subject to the provisions of ss.4.03 and its subsections, any transaction which the Managing General Partner is authorized to enter into on behalf of the Partnership under the authority granted in this section and its subsections, may be entered into by the Managing General Partner with itself or with any other general partner, the Operator, or any of their Affiliates. 4.02(d). Additional Powers. In addition to the powers granted the Managing General Partner under ss.4.02(c) and its subsections or elsewhere in this Agreement, the Managing General Partner, when specified, shall have the following additional express powers. 4.02(d)(1). Drilling Contracts. All Partnership Wells shall be drilled under the Drilling and Operating Agreement on a Cost plus 15% basis. The Managing General Partner or its Affiliates, as drilling contractor, may not do the following: (i) receive a rate that is not competitive with the rates charged by unaffiliated contractors in the same geographic region; (ii) enter into a turnkey drilling contract with the Partnership; (iii) profit by drilling in contravention of its fiduciary obligations to the Partnership; or (iv) benefit by interpositioning itself between the Partnership and the actual provider of drilling contractor services. 4.02(d)(2). Power of Attorney. 4.02(d)(2)(a). In General. Each Participant appoints the Managing General Partner his true and lawful attorney-in-fact for him and in his name, place, and stead and for his use and benefit, from time to time: (i) to create, prepare, complete, execute, file, swear to, deliver, endorse, and record any and all documents, certificates, government reports, or other instruments as may be required by law or necessary to amend this Agreement as authorized under the terms of this Agreement, or to qualify the Partnership as a limited partnership or partnership in commendam and to conduct business under the laws of any jurisdiction in which the Managing General Partner elects to qualify the Partnership or conduct business; and (ii) to create, prepare, complete, execute, file, swear to, deliver, endorse and record any and all instruments, assignments, security agreements, financing statements, certificates, and other documents as may be necessary from time to time to implement the borrowing powers granted under this Agreement. 4.02(d)(2)(b). Further Action. Each Participant authorizes the attorney-in- fact to take any further action which the attorney-in-fact considers necessary or advisable in connection with any of the foregoing. Each party acknowledges that the power of attorney granted under this section: (i) is a special power of attorney coupled with an interest and irrevocable; and (ii) shall survive the assignment by the Participant of the whole or a portion of his Units; except when the assignment is of all of the Participant's Units and the purchaser, transferee, or assignee of the Units is 18 admitted as a successor Participant, the power of attorney shall survive the delivery of the assignment for the sole purpose of enabling the attorney-in- fact to execute, acknowledge, and file any agreement, certificate, instrument or document necessary to effect the substitution. 4.02(d)(2)(c). Power of Attorney to Operator. The Managing General Partner is hereby authorized to grant a Power of Attorney to the Operator on behalf of the Partnership. 4.02(e). Borrowings and Use of Partnership Revenues. 4.02(e)(1). Power to Borrow or Use Partnership Revenues. 4.02(e)(1)(a). In General. If additional funds over the Participants' Capital Contributions are needed for Partnership operations, then the Managing General Partner may: (i) use Partnership revenues for such purposes; or (ii) the Managing General Partner and its Affiliates may advance to the Partnership the funds necessary under ss.4.03(d)(8)(b), although they are not obligated to advance the funds to the Partnership. 4.02(e)(1)(b). Limitation on Borrowing. The borrowings, other than credit transactions on open account customary in the industry to obtain goods and services, shall be subject to the following limitations: (i) the borrowings must be without recourse to the Investor General Partners and the Limited Partners except as otherwise provided in this Agreement; and (ii) the amount that may be borrowed at any one time may not exceed an amount equal to 5% of the Partnership's subscription proceeds. 4.02(f). Tax Matters Partner. 4.02(f)(1). Designation of Tax Matters Partner. The Managing General Partner is hereby designated the Tax Matters Partner of the Partnership under ss.6231(a)(7) of the Code. The Managing General Partner is authorized to act in this capacity on behalf of the Partnership and the Participants and to take any action, including settlement or litigation, which it in its sole discretion deems to be in the best interest of the Partnership. 4.02(f)(2). Costs Incurred by Tax Matters Partner. Costs incurred by the Tax Matters Partner shall be considered a Direct Cost of the Partnership. 4.02(f)(3). Notice to Participants of IRS Proceedings. The Tax Matters Partner shall notify all Participants of any partnership administrative proceedings commenced by the IRS, and thereafter shall furnish all Participants periodic reports at least quarterly on the status of the proceedings. 4.02(f)(4). Participant Restrictions. Each Participant agrees as follows: (i) he will not file the statement described in Section 6224(c)(3)(B) of the Code prohibiting the Managing General Partner as the Tax Matters Partner for the Partnership from entering into a settlement on his behalf with respect to partnership items, as that term is defined in Section 6231(a)(3) of Code, of the Partnership; (ii) he will not form or become and exercise any rights as a member of a group of Partners having a 5% or greater interest in the profits of the Partnership under Section 6223(b)(2) of the Code; and 19 (iii) the Managing General Partner is authorized to file a copy of this Agreement, or pertinent portions of this Agreement, with the IRS under Section 6224(b) of the Code if necessary to perfect the waiver of rights under this subsection. 4.03. General Rights and Obligations of the Participants and Restricted and Prohibited Transactions. 4.03(a)(1). Limited Liability of Limited Partners. Limited Partners shall not be bound by the obligations of the Partnership other than as provided under the Delaware Revised Uniform Limited Partnership Act. Limited Partners shall not be personally liable for any debts of the Partnership or any of the obligations or losses of the Partnership beyond the amount of the subscription price designated on the Subscription Agreement executed by each respective Limited Partner unless: (i) they also subscribe to the Partnership as Investor General Partners; or (ii) in the case of the Managing General Partner, it purchases Limited Partner Units. 4.03(a)(2). No Management Authority of Participants. Participants, other than the Managing General Partner if it buys Units, shall have no power over the conduct of the affairs of the Partnership. No Participant, other than the Managing General Partner if it buys Units, shall take part in the management of the business of the Partnership, or have the power to sign for or to bind the Partnership. 4.03(b). Reports and Disclosures. 4.03(b)(1). Annual Reports and Financial Statements. Beginning with the calendar year in which the Partnership had its Offering Termination Date, the Partnership shall provide each Participant an annual report within 120 days after the close of that calendar year, and beginning with the following calendar year, a report within 75 days after the end of the first six months of its calendar year, containing except as otherwise indicated, at least the information set forth below: (i) Audited financial statements of the Partnership, including a balance sheet and statements of income, cash flow, and Partners' equity, which shall be prepared on an accrual basis in accordance with generally accepted accounting principles with a reconciliation with respect to information furnished for income tax purposes and accompanied by an auditor's report containing an opinion of an independent public accountant selected by the Managing General Partner stating that his audit was made in accordance with generally accepted auditing standards and that in his opinion the financial statements present fairly the financial position, results of operations, partners' equity, and cash flows in accordance with generally accepted accounting principles. Semiannual reports are not required to be audited. (ii) A summary itemization, by type and/or classification of the total fees and compensation including any unaccountable, fixed payment reimbursements for Administrative Costs and Operating Costs, paid by the Partnership, or indirectly on behalf of the Partnership, to the Managing General Partner, the Operator, and their Affiliates. In addition, Participants shall be provided the percentage that the annual unaccountable, fixed fee reimbursement for Administrative Costs bears to annual Partnership revenues. Also, the independent certified public accountant will provide written attestation annually, which will be included in the annual report, that the method used to make allocations was consistent with the method described in ss.4.04(a)(2)(c) of this Agreement and that the total amount of costs allocated did not materially exceed the amounts actually incurred by the Managing General Partner. If the Managing General Partner subsequently decides to allocate expenses in a manner different from that described in ss.4.04(a)(2)(c) of this Agreement, then the change must be reported to the Participants together with an explanation of the reason for the change and the basis used for determining the reasonableness of the new allocation method. 20 (iii) A description of each Prospect in which the Partnership owns an interest, including: (a) the cost, location, and number of acres under Lease; and (b) the Working Interest owned in the Prospect by the Partnership. Succeeding reports, however, must only contain material changes, if any, regarding the Prospects. (iv) A list of the wells drilled or abandoned by the Partnership during the period of the report, indicating: (a) whether each of the wells has or has not been completed; (b) a statement of the cost of each well completed or abandoned; and (c) justification for wells abandoned after production has begun. (v) A description of all Farmouts, farmins, and joint ventures, made during the period of the report, including: (a) the Managing General Partner's justification for the arrangement; and (b) a description of the material terms. (vi) A schedule reflecting: (a) the total Partnership costs; (b) the costs paid by the Managing General Partner and the costs paid by the Participants; (c) the total Partnership revenues; (d) the revenues received or credited to the Managing General Partner and the revenues received and credited to the Participants; and (e) a reconciliation of the expenses and revenues in accordance with the provisions of Article V. Additionally, on request the Managing General Partner will provide the information specified by Form 10-Q (if such report is required to be filed with the SEC) within 45 days after the close of each quarterly fiscal period. 4.03(b)(2). Tax Information. The Partnership shall, by March 15 of each year, prepare, or supervise the preparation of, and transmit to each Participant the information needed for the Participant to file the following: (i) his federal income tax return; (ii) any required state income tax return; and (iii) any other reporting or filing requirements imposed by any governmental agency or authority. 4.03(b)(3). Reserve Report. Beginning with the second calendar year after the Offering Termination Date and every year thereafter, the Partnership shall provide to each Participant the following: (i) a summary of the computation of the Partnership's total oil and gas Proved Reserves; (ii) a summary of the computation of the present worth of the reserves determined using: 21 (a) a discount rate of 10%; (b) a constant price for the oil; and (c) basing the price of gas on the existing gas contracts; (iii) a statement of each Participant's interest in the reserves; and (iv) an estimate of the time required for the extraction of the reserves with a statement that because of the time period required to extract the reserves the present value of revenues to be obtained in the future is less than if immediately receivable. The reserve computations shall be based on engineering reports prepared by the Managing General Partner and reviewed by an Independent Expert. Also, if there is an event that leads to the reduction of the Partnership's Proved Reserves of 10% or more, excluding: (i) reduction as a result of normal production; (ii) sales of reserves; or (iii) product price changes, then a computation and estimate must be sent to each Participant within 90 days. 4.03(b)(4). Cost of Reports. The cost of all reports described in this ss.4.03(b) shall be paid by the Partnership as Direct Costs. 4.03(b)(5). Participant Access to Records. The Participants and/or their representatives shall be permitted access to all Partnership records. The Participant may inspect and copy any of the records after giving adequate notice to the Managing General Partner at any reasonable time. Notwithstanding the foregoing, the Managing General Partner may keep logs, well reports, and other drilling and operating data confidential for reasonable periods of time. The Managing General Partner may release information concerning the operations of the Partnership to the sources that are customary in the industry or required by rule, regulation, or order of any regulatory body. 4.03(b)(6). Required Length of Time to Hold Records. The Managing General Partner must maintain and preserve during the term of the Partnership and for six years thereafter all accounts, books and other relevant documents which include: (i) a record that a Participant meets the suitability standards established in connection with an investment in the Partnership; and (ii) any appraisal of the fair market value of the Leases as set forth in ss.4.01(a)(4) or fair market value of any producing property as set forth in ss.4.03(d)(3). 4.03(b)(7). Participant Lists. The following provisions apply regarding access to the list of Participants: (i) an alphabetical list of the names, addresses, and business telephone numbers of the Participants along with the number of Units held by each of them (the "Participant List") must be maintained as a part of the Partnership's books and records and be available for inspection by any Participant or his designated agent at the home office of the Partnership on the Participant's request; (ii) the Participant List must be updated at least quarterly to reflect changes in the information contained in the Participant List; 22 (iii) a copy of the Participant List must be mailed to any Participant requesting the Participant List within 10 days of the written request, printed in alphabetical order on white paper, and in a readily readable type size in no event smaller than 10-point type and a reasonable charge for copy work will be charged by the Partnership; (iv) the purposes for which a Participant may request a copy of the Participant List include, without limitation, matters relating to Participant's voting rights under this Agreement and the exercise of Participant's rights under the federal proxy laws; and (v) if the Managing General Partner neglects or refuses to exhibit, produce, or mail a copy of the Participant List as requested, the Managing General Partner shall be liable to any Participant requesting the list for the costs, including attorneys fees, incurred by that Participant for compelling the production of the Participant List, and for actual damages suffered by any Participant by reason of the refusal or neglect. It shall be a defense that the actual purpose and reason for the request for inspection or for a copy of the Participant List is to secure the list of Participants or other information for the purpose of selling the list or information or copies of the list, or of using the same for a commercial purpose other than in the interest of the applicant as a Participant relative to the affairs of the Partnership. The Managing General Partner will require the Participant requesting the Participant List to represent in writing that the list was not requested for a commercial purpose unrelated to the Participant's interest in the Partnership. The remedies provided under this subsection to Participants requesting copies of the Participant List are in addition to, and shall not in any way limit, other remedies available to Participants under federal law or the laws of any state. 4.03(b)(8). State Filings. Concurrently with their transmittal to Participants, and as required, the Managing General Partner shall file a copy of each report provided for in this ss.4.03(b) with: (i) the California Commissioner of Corporations; and (ii) The Arizona Corporation Commission; and (iii) the securities commissions of other states which request the report. 4.03(c). Meetings of Participants. 4.03(c)(1). Procedure for a Participant Meeting. 4.03(c)(1)(a). Meetings May Be Called by Managing General Partner or Participants. Meetings of the Participants may be called as follows: (i) by the Managing General Partner; or (ii) by Participants whose Units equal 10% or more of the total Units for any matters for which Participants may vote. The call for a meeting by Participants shall be deemed to have been made on receipt by the Managing General Partner of a written request from holders of the requisite percentage of Units stating the purpose(s) of the meeting. 4.03(c)(1)(b). Notice Requirement. The Managing General Partner shall deposit in the United States mail within 15 days after the receipt of the request, written notice to all Participants of the meeting and the purpose of the meeting. The meeting shall be held on a date not less than 30 days nor more than 60 days after the date of the mailing of the notice, at a reasonable time and place. Notwithstanding the foregoing, the date for notice of the meeting may be extended for a period of up to 60 days if, in the opinion of the Managing General Partner, the additional time is necessary to permit preparation of proxy or information statements or other documents required to be delivered in connection with the meeting by the SEC or other regulatory authorities. 23 4.03(c)(1)(c). May Vote by Proxy. Participants shall have the right to vote at any Participant meeting either: (i) in person; or (ii) by proxy. 4.03(c)(2). Special Voting Rights. At the request of Participants whose Units equal 10% or more of the total Units, the Managing General Partner shall call for a vote by Participants. Each Unit is entitled to one vote on all matters, and each fractional Unit is entitled to that fraction of one vote equal to the fractional interest in the Unit. Participants whose Units equal a majority of the total Units may, without the concurrence of the Managing General Partner or its Affiliates, vote to: (i) dissolve the Partnership; (ii) remove the Managing General Partner and elect a new Managing General Partner; (iii) elect a new Managing General Partner if the Managing General Partner elects to withdraw from the Partnership; (iv) remove the Operator and elect a new Operator; (v) approve or disapprove the sale of all or substantially all of the assets of the Partnership; (vi) cancel any contract for services with the Managing General Partner, the Operator, or their Affiliates without penalty on 60 days notice; and (vii) amend this Agreement; provided however: (a) any amendment may not increase the duties or liabilities of any Participant or the Managing General Partner or increase or decrease the profit or loss sharing or required Capital Contribution of any Participant or the Managing General Partner without the approval of the Participant or the Managing General Partner; and (b) any amendment may not affect the classification of Partnership income and loss for federal income tax purposes without the unanimous approval of all Participants. 4.03(c)(3). Restrictions on Managing General Partner's Voting Rights. With respect to Units owned by the Managing General Partner or its Affiliates, the Managing General Partner and its Affiliates may vote or consent on all matters other than the following: (i) the matters set forth in ss.4.03(c)(2)(ii) and (iv) above; or (ii) any transaction between the Partnership and the Managing General Partner or its Affiliates. In determining the requisite percentage in interest of Units necessary to approve any Partnership matter on which the Managing General Partner and its Affiliates may not vote or consent, any Units owned by the Managing General Partner and its Affiliates shall not be included. 4.03(c)(4). Restrictions on Limited Partner Voting Rights. The exercise by the Limited Partners of the rights granted Participants under ss.4.03(c), except for the special voting rights granted Participants under ss.4.03(c)(2), shall be subject to the prior legal determination that the grant or exercise of the powers will not adversely affect the limited liability of Limited Partners. Notwithstanding the foregoing, if in the opinion of counsel to the Partnership the legal determination is not necessary under Delaware law to maintain the limited liability of the Limited Partners, then it shall not be required. A legal determination under this paragraph may be made either pursuant to: 24 (i) an opinion of counsel, the counsel being independent of the Partnership and selected on the vote of Limited Partners whose Units equal a majority of the total Units held by Limited Partners; or (ii) a declaratory judgment issued by a court of competent jurisdiction. The Investor General Partners may exercise the rights granted to the Participants whether or not the Limited Partners can participate in the vote if the Investor General Partners represent the requisite percentage of Units necessary to take the action. 4.03(d). Transactions with the Managing General Partner. 4.03(d)(1). Transfer of Equal Proportionate Interest. When the Managing General Partner or an Affiliate (excluding another Program in which the interest of the Managing General Partner or its Affiliates is substantially similar to or less than their interest in the Partnership) sells, transfers or conveys any natural gas, oil or other mineral interests or property to the Partnership, it must, at the same time, sell, transfer or convey to the Partnership an equal proportionate interest in all its other property in the same Prospect. Notwithstanding, a Prospect shall be deemed to consist of the drilling or spacing unit on which the well will be drilled by the Partnership, which is the minimum area permitted by state law or local practice on which one well may be drilled, if the following conditions are met: (i) the geological feature to which the well will be drilled contains Proved Reserves; and (ii) the drilling or spacing unit protects against drainage. With respect to a natural gas or oil Prospect located in Ohio, Pennsylvania and New York on which a well will be drilled by the Partnership to test the Clinton/Medina geological formation or the Mississippian and/or Upper Devonian Sandstone reservoirs, a Prospect shall be deemed to consist of the drilling and spacing unit if it meets the test in the preceding sentence. Additionally, for a period of five years after the drilling of the Partnership Well neither the Managing General Partner nor its Affiliates may drill any well: (i) in the Clinton/Medina geological formation within 1,650 feet of an existing Partnership Well in Pennsylvania or within 1,000 feet of an existing Partnership Well in Ohio; or (ii) in the Mississippian/Upper Devonian Sandstone reservoirs in Fayette County and Greene County, Pennsylvania within 1,000 feet of an existing Partnership Well, although existing wells may be re-entered by parties other than the Partnership even though they are not 1,000 feet from each other. If the Partnership abandons its interest in a well, then this restriction will continue for one year following the abandonment. If the area constituting the Partnership's Prospect is subsequently enlarged to encompass any area in which the Managing General Partner or an Affiliate (excluding another Program in which the interest of the Managing General Partner or its Affiliates is substantially similar to or less than their interest in the Partnership) owns a separate property interest and the activities of the Partnership were material in establishing the existence of Proved Undeveloped Reserves that are attributable to the separate property interest, then the separate property interest or a portion thereof must be sold, transferred, or conveyed to the Partnership as set forth in this section and ss.ss.4.01(a)(4) and 4.03(d)(2). Notwithstanding the foregoing, Prospects in the Clinton/Medina geological formation, the Mississippian and/or Upper Devonian Sandstone reservoirs, or any other formation or reservoir shall not be enlarged or contracted if the Prospect was limited to the drilling or spacing unit because the well was being drilled to Proved Reserves in the geological formation and the drilling or spacing unit protected against drainage. 4.03(d)(2). Transfer of Less than the Managing General Partner's and its Affiliates' Entire Interest. A sale, transfer or a conveyance to the Partnership of less than all of the ownership of the Managing General Partner or an Affiliate (excluding another Program in which the interest of the Managing General Partner or its Affiliates is substantially similar to or less than their interest in the Partnership) in any Prospect shall not be made unless: 25 (i) the interest retained by the Managing General Partner or the Affiliate is a proportionate Working Interest; (ii) the respective obligations of the Managing General Partner or its Affiliates and the Partnership are substantially the same after the sale of the interest by the Managing General Partner or its Affiliates; and (iii) the Managing General Partner's interest in revenues does not exceed the amount proportionate to its retained Working Interest. This section does not prevent the Managing General Partner or its Affiliates from subsequently dealing with their retained interest as they may choose with unaffiliated parties or Affiliated partnerships. 4.03(d)(3). Limitations on Sale of Undeveloped and Developed Leases to the Managing General Partner. Other than another Program managed by the Managing General Partner and its Affiliates as set forth in ss.ss.4.03(d)(5) and 4.03(d)(9), the Managing General Partner and its Affiliates shall not Farmout or purchase any undeveloped Leases from the Partnership other than at the higher of Cost or fair market value. The Managing General Partner and its Affiliates, other than an Affiliated Income Program, may not purchase any producing natural gas or oil property from the Partnership unless: (i) the sale is in connection with the liquidation of the Partnership; or (ii) the Managing General Partner's well supervision fees under the Drilling and Operating Agreement for the well have exceeded the net revenues of the well, determined without regard to the Managing General Partner's well supervision fees for the well, for a period of at least three consecutive months. In both (i) and (ii), the sale must be at fair market value supported by an appraisal of an Independent Expert selected by the Managing General Partner. 4.03(d)(4). Limitations on Activities of the Managing General Partner and its Affiliates on Leases Acquired by the Partnership. During a period of five years after the Offering Termination Date of the Partnership, if the Managing General Partner or any of its Affiliates (excluding another Program in which the interest of the Managing General Partner or its Affiliates is substantially similar to or less than their interest in the Partnership) proposes to acquire an interest from an unaffiliated person in a Prospect in which the Partnership possesses an interest or in a Prospect in which the Partnership's interest has been terminated without compensation within one year preceding the proposed acquisition, then the following conditions shall apply: (i) if the Managing General Partner or the Affiliate (excluding another Program in which the interest of the Managing General Partner or its Affiliates is substantially similar to or less than their interest in the Partnership) does not currently own property in the Prospect separately from the Partnership, then neither the Managing General Partner nor the Affiliate shall be permitted to purchase an interest in the Prospect; and (ii) if the Managing General Partner or the Affiliate (excluding another Program in which the interest of the Managing General Partner or its Affiliates is substantially similar to or less than their interest in the Partnership) currently owns a proportionate interest in the Prospect separately from the Partnership, then the interest to be acquired shall be divided between the Partnership and the Managing General Partner or the Affiliate in the same proportion as is the other property in the Prospect. Provided, however, if cash or financing is not available to the Partnership to enable it to complete a purchase of the additional interest to which it is entitled, then neither the Managing General Partner nor the Affiliate shall be permitted to purchase any additional interest in the Prospect. 4.03(d)(5). Transfer of Leases Between Affiliated Limited Partnerships. The transfer of an undeveloped Lease from the Partnership to an Affiliated Drilling Program must be made at fair market value if the undeveloped Lease has been held for 26 more than two years. Otherwise, if the Managing General Partner deems it to be in the best interest of the Partnership, the transfer may be made at Cost. An Affiliated Income Program may purchase a producing natural gas and oil property from the Partnership at any time at: (i) fair market value as supported by an appraisal from an Independent Expert if the property has been held by the Partnership for more than six months or there have been significant expenditures made in connection with the property; or (ii) Cost as adjusted for intervening operations if the Managing General Partner deems it to be in the best interest of the Partnership. However, these prohibitions shall not apply to joint ventures or Farmouts among Affiliated partnerships, provided that: (i) the respective obligations and revenue sharing of all parties to the transaction are substantially the same; and (ii) the compensation arrangement or any other interest or right of either the Managing General Partner or its Affiliates is the same in each Affiliated partnership or if different, the aggregate compensation of the Managing General Partner or the Affiliate is reduced to reflect the lower compensation arrangement. 4.03(d)(6). Sale of All Assets. The sale of all or substantially all of the assets of the Partnership, including without limitation, Leases, wells, equipment and production therefrom, shall be made only with the consent of Participants whose Units equal a majority of the total Units. 4.03(d)(7). Services. 4.03(d)(7)(a). Competitive Rates. The Managing General Partner and any Affiliate shall not render to the Partnership any oil field, equipage, or other services nor sell or lease to the Partnership any equipment or related supplies unless: (i) the person is engaged, independently of the Partnership and as an ordinary and ongoing business, in the business of rendering the services or selling or leasing the equipment and supplies to a substantial extent to other persons in the natural gas and oil industry in addition to the partnerships in which the Managing General Partner or an Affiliate has an interest; and (ii) the compensation, price, or rental therefor is competitive with the compensation, price, or rental of other persons in the area engaged in the business of rendering comparable services or selling or leasing comparable equipment and supplies which could reasonably be made available to the Partnership. If the person is not engaged in such a business, then the compensation, price or rental shall be the Cost of the services, equipment or supplies to the person or the competitive rate which could be obtained in the area, whichever is less. 4.03(d)(7)(b). If Not Disclosed in the Prospectus or This Agreement Then Services by the Managing General Partner Must be Described in a Separate Contract and Cancelable. Any services for which the Managing General Partner or an Affiliate is to receive compensation other than those described in this Agreement or the Prospectus shall be set forth in a written contract which precisely describes the services to be rendered and all compensation to be paid. These contracts are cancelable without penalty on 60 days written notice by Participants whose Units equal a majority of the total Units. 4.03(d)(8). Loans. 4.03(d)(8)(a). No Loans from the Partnership. No loans or advances shall be made by the Partnership to the Managing General Partner or any Affiliate. 4.03(d)(8)(b). Loans to the Partnership. Neither the Managing General Partner nor any Affiliate shall loan money to the Partnership if the interest to be charged exceeds either: 27 (i) the Managing General Partner's or the Affiliate's interest cost; or (ii) that which would be charged to the Partnership, without reference to the Managing General Partner's or the Affiliate's financial abilities or guarantees, by unrelated lenders, on comparable loans for the same purpose. Neither the Managing General Partner nor any Affiliate shall receive points or other financing charges or fees, regardless of the amount, although the actual amount of the charges incurred from third-party lenders may be reimbursed to the Managing General Partner or the Affiliate. 4.03(d)(9). Farmouts. The Managing General Partner shall not enter into a Farmout to avoid its paying its share of costs related to drilling an undeveloped Lease. The Partnership shall not Farmout an undeveloped Lease or well activity to the Managing General Partner or its Affiliates except as set forth in ss.4.03(d)(3). Notwithstanding, this restriction shall not apply to Farmouts between the Partnership and another partnership managed by the Managing General Partner or its Affiliates, either separately or jointly, provided that the respective obligations and revenue sharing of all parties to the transactions are substantially the same and the compensation arrangement or any other interest or right of the Managing General Partner or its Affiliates is the same in each partnership, or, if different, the aggregate compensation of the Managing General Partner and its Affiliates is reduced to reflect the lower compensation agreement. The Partnership may Farmout an undeveloped lease or well activity only if the Managing General Partner, exercising the standard of a prudent operator, determines that: (i) the Partnership lacks the funds to complete the oil and gas operations on the Lease or well and cannot obtain suitable financing; (ii) drilling on the Lease or the intended well activity would concentrate excessive funds in one location, creating undue risks to the Partnership; (iii) the Leases or well activity have been downgraded by events occurring after assignment to the Partnership so that development of the Leases or well activity would not be desirable; or (iv) the best interests of the Partnership would be served. If the Partnership Farmouts a Lease or well activity, the Managing General Partner must retain on behalf of the Partnership the economic interests and concessions as a reasonably prudent oil and gas operator would or could retain under the circumstances prevailing at the time, consistent with industry practices. 4.03(d)(10). No Compensating Balances. Neither the Managing General Partner nor any Affiliate shall use the Partnership's funds as compensating balances for its own benefit. 4.03(d)(11). Future Production. Neither the Managing General Partner nor any Affiliate shall commit the future production of a well developed by the Partnership exclusively for its own benefit. 4.03(d)(12). Marketing Arrangements. Subject to ss.4.06(c), all benefits from marketing arrangements or other relationships affecting the property of the Managing General Partner or its Affiliates and the Partnership shall be fairly and equitably apportioned according to the respective interests of each in the property. The Managing General Partner shall treat all wells in a geographic area equally concerning to whom and at what price the Partnership's natural gas and oil will be sold and to whom and at what price the natural gas and oil of other natural gas and oil Programs which the Managing General Partner has sponsored or will sponsor will be sold. For example, the Managing General Partner calculates a weighted average selling price for all the natural gas and oil sold in a geographic area by taking all the money received from the sale of all the natural gas and oil sold to its customers in a geographic area and dividing by the volume of all natural gas and oil sold from the wells in that geographic area. The Managing General Partner, in its sole discretion, shall determine what constitutes a geographic area. 28 4.03(d)(13). Advance Payments. Advance payments by the Partnership to the Managing General Partner and its Affiliates are prohibited except when advance payments are required to secure the tax benefits of prepaid drilling costs and for a business purpose. 4.03(d)(14). No Rebates. No rebates or give-ups may be received by the Managing General Partner or any Affiliate nor may the Managing General Partner or any Affiliate participate in any reciprocal business arrangements which would circumvent these guidelines. 4.03(d)(15). Participation in Other Partnerships. If the Partnership participates in other partnerships or joint ventures (multi-tier arrangements), then the terms of any of these arrangements shall not result in the circumvention of any of the requirements or prohibitions contained in this Agreement, including the following: (i) there shall be no duplication or increase in organization and offering expenses, the Managing General Partner's compensation, Partnership expenses or other fees and costs; (ii) there shall be no substantive alteration in the fiduciary and contractual relationship between the Managing General Partner and the Participants; and (iii) there shall be no diminishment in the voting rights of the Participants. 4.03(d)(16). Roll-Up Limitations. 4.03(d)(16)(a). Requirement for Appraisal and Its Assumptions. In connection with a proposed Roll-Up, an appraisal of all Partnership assets shall be obtained from a competent Independent Expert. If the appraisal will be included in a prospectus used to offer securities of a Roll-Up Entity, then the appraisal shall be filed with the SEC and the Administrator as an exhibit to the registration statement for the offering. Thus, an issuer using the appraisal shall be subject to liability for violation of Section 11 of the Securities Act of 1933 and comparable provisions under state law for any material misrepresentations or material omissions in the appraisal. Partnership assets shall be appraised on a consistent basis. The appraisal shall be based on all relevant information, including current reserve estimates prepared by an independent petroleum consultant, and shall indicate the value of the Partnership's assets as of a date immediately before the announcement of the proposed Roll-Up transaction. The appraisal shall assume an orderly liquidation of the Partnership's assets over a 12-month period. The terms of the engagement of the Independent Expert shall clearly state that the engagement is for the benefit of the Partnership and the Participants. A summary of the independent appraisal, indicating all material assumptions underlying the appraisal, shall be included in a report to the Participants in connection with a proposed Roll-Up. 4.03(d)(16)(b). Rights of Participants Who Vote Against Proposal. In connection with a proposed Roll-Up, Participants who vote "no" on the proposal shall be offered the choice of: (i) accepting the securities of the Roll-Up Entity offered in the proposed Roll-Up; or (ii) one of the following: (a) remaining as Participants in the Partnership and preserving their Units in the Partnership on the same terms and conditions as existed previously; or (b) receiving cash in an amount equal to the Participants' pro rata share of the appraised value of the net assets of the Partnership based on their respective number of Units. 4.03(d)(16)(c). No Roll-Up If Diminishment of Voting Rights. The Partnership shall not participate in any proposed Roll-Up which, if approved, would result in the diminishment of any Participant's voting rights under the Roll-Up Entity's chartering agreement. 29 In no event shall the democracy rights of Participants in the Roll-Up Entity be less than those provided for under ss.ss.4.03(c)(1) and 4.03(c)(2) of this Agreement. If the Roll-Up Entity is a corporation, then the democracy rights of Participants shall correspond to the democracy rights provided for in this Agreement to the greatest extent possible. 4.03(d)(16)(d). No Roll-Up If Accumulation of Shares Would be Impeded. The Partnership shall not participate in any proposed Roll-Up transaction which includes provisions which would operate to materially impede or frustrate the accumulation of shares by any purchaser of the securities of the Roll-Up Entity, except to the minimum extent necessary to preserve the tax status of the Roll-Up Entity. The Partnership shall not participate in any proposed Roll-Up transaction which would limit the ability of a Participant to exercise the voting rights of its securities of the Roll-Up Entity on the basis of the number of Units held by that Participant. 4.03(d)(16)(e). No Roll-Up If Access to Records Would Be Limited. The Partnership shall not participate in a Roll-Up in which Participants' rights of access to the records of the Roll-Up Entity will be less than those provided for under ss.ss.4.03(b)(5), 4.03(b)(6) and 4.03(b)(7) of this Agreement. 4.03(d)(16)(f). Cost of Roll-Up. The Partnership shall not participate in any proposed Roll-Up transaction in which any of the costs of the transaction would be borne by the Partnership if Participants whose Units equal 66% of the total Units do not vote to approve the proposed Roll-Up. 4.03(d)(16)(g). Roll-Up Approval. The Partnership shall not participate in a Roll-Up transaction unless the Roll-Up transaction is approved by Participants whose Units equal 66% of the total Units. 4.03(d)(17). Disclosure of Binding Agreements. Any agreement or arrangement which binds the Partnership must be disclosed in the Prospectus. 4.03(d)(18). Transactions Must Be Fair and Reasonable. Neither the Managing General Partner nor any Affiliate shall sell, transfer, or convey any property to or purchase any property from the Partnership, directly or indirectly, except: (i) under transactions that are fair and reasonable; nor (ii) take any action with respect to the assets or property of the Partnership which does not primarily benefit the Partnership. 4.04. Designation, Compensation and Removal of Managing General Partner and Removal of Operator. 4.04(a). Managing General Partner. 4.04(a)(1). Term of Service. Atlas shall serve as the Managing General Partner of the Partnership until either it: (i) is removed pursuant to ss.4.04(a)(3); or (ii) withdraws pursuant to ss.4.04(a)(3)(f). 4.04(a)(2). Compensation of Managing General Partner. In addition to the compensation set forth in ss.ss.4.01(a)(4) and 4.02(d)(1), the Managing General Partner shall receive the compensation set forth in ss.ss.4.04(a)(2)(b) through 4.04(a)(2)(g). 4.04(a)(2)(a). Charges Must Be Necessary and Reasonable. Charges by the Managing General Partner for goods and services must be fully supportable as to: (i) the necessity of the goods and services; and (ii) the reasonableness of the amount charged. All actual and necessary expenses incurred by the Partnership may be paid out of the Partnership's subscription proceeds and revenues. 30 4.04(a)(2)(b). Direct Costs. The Managing General Partner and its Affiliates shall be reimbursed for all Direct Costs. Direct Costs, however, shall be billed directly to and paid by the Partnership to the extent practicable. 4.04(a)(2)(c). Administrative Costs. The Managing General Partner shall receive an unaccountable, fixed payment reimbursement for its Administrative Costs of $75 per well per month. The unaccountable, fixed payment reimbursement of $75 per well per month shall be subject to the following: (i) it shall not be increased in amount during the term of the Partnership; (ii) it shall be proportionately reduced to the extent the Partnership acquires less than 100% of the Working Interest in the well; (iii) it shall be the entire payment to reimburse the Managing General Partner for the Partnership's Administrative Costs; and (iv) it shall not be received for plugged or abandoned wells. 4.04(a)(2)(d). Gas Gathering. The Managing General Partner shall be responsible for gathering and transporting the natural gas produced by the Partnership to interstate pipeline systems, local distribution companies and end-users in the area and shall receive a gathering fee at a competitive rate for gathering and transporting the Partnership's gas. If the Partnership's gas production is gathered and transported through the gathering system owned by Atlas Pipeline Partners, then the Managing General Partner shall apply its gathering fee towards the agreement between Atlas Pipeline Partners and Atlas America, Inc., Resource Energy, Inc., and Viking Resources Corporation. If the Partnership's gas production is gathered and transferred through the gathering system owned by a third-party, then the Managing General Partner shall pay a portion or all of its gathering fee to the third-party gathering the natural gas. 4.04(a)(2)(e). Dealer-Manager Fee. Subject to ss.3.03(a)(1), the Dealer- Manager shall receive on each Unit sold to investors: (i) a 2.5% Dealer-Manager fee; (ii) a 7% Sales Commission; (iii) a .5% accountable marketing expense fee; and (iv) a .5% reimbursement of the Selling Agents' bona fide accountable due diligence expenses. 4.04(a)(2)(f). Drilling and Operating Agreement. The Managing General Partner and its Affiliates shall receive compensation as set forth in the Drilling and Operating Agreement. 4.04(a)(2)(g). Other Transactions. The Managing General Partner and its Affiliates may enter into transactions pursuant to ss.4.03(d)(7) with the Partnership and shall be entitled to compensation under this section. 4.04(a)(3). Removal of Managing General Partner. 4.04(a)(3)(a). Majority Vote Required to Remove the Managing General Partner. The Managing General Partner may be removed at any time on 60 days' advance written notice to the outgoing Managing General Partner by the affirmative vote of Participants whose Units equal a majority of the total Units. If the Participants vote to remove the Managing General Partner from the Partnership, then Participants must elect by an affirmative vote of Participants whose Units equal a majority of the total Units either to: (i) terminate, dissolve, and wind up the Partnership; or (ii) continue as a successor limited partnership under all the terms of this Partnership Agreement as provided in ss.7.01(c). 31 If the Participants elect to continue as a successor limited partnership, then the Managing General Partner shall not be removed until a substituted Managing General Partner has been selected by an affirmative vote of Participants whose Units equal a majority of the total Units and installed as such. 4.04(a)(3)(b). Valuation of Managing General Partner's Interest in the Partnership. If the Managing General Partner is removed, then its interest in the Partnership shall be determined by appraisal by a qualified Independent Expert. The Independent Expert shall be selected by mutual agreement between the removed Managing General Partner and the incoming Managing General Partner. The appraisal shall take into account an appropriate discount, to reflect the risk of recovery of natural gas and oil reserves, but not less than that used in the most recent presentment offer, if any. The cost of the appraisal shall be borne equally by the removed Managing General Partner and the Partnership. 4.04(a)(3)(c). Incoming Managing General Partner's Option to Purchase. The incoming Managing General Partner shall have the option to purchase 20% of the removed Managing General Partner's interest in the Partnership as Managing General Partner and not as a Participant for the value determined by the Independent Expert. 4.04(a)(3)(d). Method of Payment. The method of payment for the removed Managing General Partner's interest must be fair and protect the solvency and liquidity of the Partnership. The method of payment shall be as follows: (i) when the termination is voluntary, the method of payment shall be a non-interest bearing unsecured promissory note with principal payable, if at all, from distributions which the Managing General Partner otherwise would have received under the Partnership Agreement had the Managing General Partner not been terminated; and (ii) when the termination is involuntary, the method of payment shall be an interest bearing promissory note coming due in no less than five years with equal installments each year. The interest rate shall be that charged on comparable loans. 4.04(a)(3)(e). Termination of Contracts. The removed Managing General Partner, at the time of its removal shall cause, to the extent it is legally possible, its successor to be transferred or assigned all its rights, obligations and interests as Managing General Partner of the Partnership in contracts entered into by it on behalf of the Partnership. In any event, the removed Managing General Partner shall cause its rights, obligations and interests as Managing General Partner of the Partnership in any such contract to terminate at the time of its removal. Notwithstanding any other provision in this Agreement, the Partnership or the successor Managing General Partner shall not: (i) be a party to any natural gas supply agreement that the Managing General Partner or its Affiliates enters into with a third-party; (ii) have any rights pursuant to such natural gas supply agreement; or (iii) receive any interest in the Managing General Partner's and its Affiliates' pipeline or gathering system or compression facilities. 4.04(a)(3)(f). The Managing General Partner's Right to Voluntarily Withdraw. At any time beginning 10 years after the Offering Termination Date and the Partnership's primary drilling activities, the Managing General Partner may voluntarily withdraw as Managing General Partner on giving 120 days' written notice of withdrawal to the Participants. If the Managing General Partner withdraws, then the following conditions shall apply: (i) the Managing General Partner's interest in the Partnership shall be determined as described in ss.4.04(a)(3)(b) above with respect to removal; and (ii) the interest shall be distributed to the Managing General Partner as described in ss.4.04(a)(3)(d)(i) above. 32 Any successor Managing General Partner shall have the option to purchase 20% of the withdrawing Managing General Partner's interest in the Partnership at the value determined as described above with respect to removal. 4.04(a)(3)(g). The Managing General Partner's Right to Withdraw Property Interest. The Managing General Partner has the right at any time to withdraw a property interest held by the Partnership in the form of a Working Interest in the Partnership Wells equal to or less than its respective interest in the revenues of the Partnership under the conditions set forth in ss.6.03. If the Managing General Partner withdraws an interest, then the Managing General Partner shall: (i) pay the expenses of withdrawing; and (ii) fully indemnify the Partnership against any additional expenses which may result from a partial withdrawal of its interests including insuring that a greater amount of Direct Costs or Administrative Costs is not allocated to the Participants. 4.04(a)(4). Removal of Operator. The Operator may be removed and a new Operator may be substituted at any time on 60 days advance written notice to the outgoing Operator by the Managing General Partner acting on behalf of the Partnership on the affirmative vote of Participants whose Units equal a majority of the total Units. The Operator shall not be removed until a substituted Operator has been selected by an affirmative vote of Participants whose Units equal a majority of the total Units and installed as such. 4.05. Indemnification and Exoneration. 4.05(a)(1). Standards for the Managing General Partner Not Incurring Liability to the Partnership or Participants. The Managing General Partner, the Operator, and their Affiliates shall not have any liability whatsoever to the Partnership or to any Participant for any loss suffered by the Partnership or Participants which arises out of any action or inaction of the Managing General Partner, the Operator, or their Affiliates if: (i) the Managing General Partner, the Operator, and their Affiliates determined in good faith that the course of conduct was in the best interest of the Partnership; (ii) the Managing General Partner, the Operator, and their Affiliates were acting on behalf of, or performing services for, the Partnership; and (iii) the course of conduct did not constitute negligence or misconduct of the Managing General Partner, the Operator, or their Affiliates. 4.05(a)(2). Standards for Managing General Partner Indemnification. The Managing General Partner, the Operator, and their Affiliates shall be indemnified by the Partnership against any losses, judgments, liabilities, expenses, and amounts paid in settlement of any claims sustained by them in connection with the Partnership, provided that: (i) the Managing General Partner, the Operator, and their Affiliates determined in good faith that the course of conduct which caused the loss or liability was in the best interest of the Partnership; (ii) the Managing General Partner, the Operator, and their Affiliates were acting on behalf of, or performing services for, the Partnership; and (iii) the course of conduct was not the result of negligence or misconduct of the Managing General Partner, the Operator, or their Affiliates. Provided, however, payments arising from such indemnification or agreement to hold harmless are recoverable only out of the following: (i) tangible net assets; 33 (ii) revenues from operations; and (iii) any insurance proceeds. 4.05(a)(3). Standards for Securities Law Indemnification. Notwithstanding anything to the contrary contained in the above, the Managing General Partner, the Operator, and their Affiliates and any person acting as a broker/dealer shall not be indemnified for any losses, liabilities or expenses arising from or out of an alleged violation of federal or state securities laws by such party unless: (i) there has been a successful adjudication on the merits of each count involving alleged securities law violations as to the particular indemnitee; (ii) the claims have been dismissed with prejudice on the merits by a court of competent jurisdiction as to the particular indemnitee; or (iii) a court of competent jurisdiction approves a settlement of the claims against a particular indemnitee and finds that indemnification of the settlement and the related costs should be made, and the court considering the request for indemnification has been advised of the position of the SEC, the Massachusetts Securities Division, and any state securities regulatory authority in which plaintiffs claim they were offered or sold Units with respect to the issue of indemnification for violation of securities laws. 4.05(a)(4). Standards for Advancement of Funds to the Managing General Partner and Insurance. The advancement of Partnership funds to the Managing General Partner, the Operator, or their Affiliates for legal expenses and other costs incurred as a result of any legal action for which indemnification is being sought is permissible only if the Partnership has adequate funds available and the following conditions are satisfied: (i) the legal action relates to acts or omissions with respect to the performance of duties or services on behalf of the Partnership; (ii) the legal action is initiated by a third-party who is not a Participant, or the legal action is initiated by a Participant and a court of competent jurisdiction specifically approves the advancement; and (iii) the Managing General Partner or its Affiliates undertake to repay the advanced funds to the Partnership, together with the applicable legal rate of interest thereon, in cases in which such party is found not to be entitled to indemnification. The Partnership shall not bear the cost of that portion of insurance which insures the Managing General Partner, the Operator, or their Affiliates for any liability for which they could not be indemnified pursuant to ss.ss.4.05(a)(1) and 4.05(a)(2). 4.05(b). Liability of Partners. Under the Delaware Revised Uniform Limited Partnership Act, the Investor General Partners are liable jointly and severally for all liabilities and obligations of the Partnership. Notwithstanding the foregoing, as among themselves, the Investor General Partners agree that each shall be solely and individually responsible only for his pro rata share of the liabilities and obligations of the Partnership based on his respective number of Units. In addition, the Managing General Partner agrees to use its corporate assets to indemnify each of the Investor General Partners against all Partnership related liabilities which exceed the Investor General Partner's interest in the undistributed net assets of the Partnership and insurance proceeds, if any. Further, the Managing General Partner agrees to indemnify each Investor General Partner against any personal liability as a result of the unauthorized acts of another Investor General Partner. 34 If the Managing General Partner provides indemnification, then each Investor General Partner who has been indemnified shall transfer and subrogate his rights for contribution from or against any other Investor General Partner to the Managing General Partner. 4.05(c). Order of Payment of Claims. Claims shall be paid as follows: (i) first, out of any insurance proceeds; (ii) second, out of Partnership assets and revenues; and (iii) last, by the Managing General Partner as provided in ss.ss.3.05(b)(2) and (3) and 4.05(b). No Limited Partner shall be required to reimburse the Managing General Partner, the Operator, or their Affiliates or the Investor General Partners for any liability in excess of his agreed Capital Contribution, except: (i) for a liability resulting from the Limited Partner's unauthorized participation in Partnership management; or (ii) from some other breach by the Limited Partner of this Agreement. 4.05(d). Authorized Transactions Are Not Deemed to Be a Breach. No transaction entered into or action taken by the Partnership or the Managing General Partner, the Operator, or their Affiliates, which is authorized by this Agreement shall be deemed a breach of any obligation owed by the Managing General Partner, the Operator, or their Affiliates to the Partnership or the Participants. 4.06. Other Activities. 4.06(a). The Managing General Partner May Pursue Other Natural Gas and Oil Activities for Its Own Account. The Managing General Partner, the Operator, and their Affiliates are now engaged, and will engage in the future, for their own account and for the account of others, including other investors, in all aspects of the natural gas and oil business. This includes without limitation, the evaluation, acquisition, and sale of producing and nonproducing Leases, and the exploration for and production of natural gas, oil and other minerals. The Managing General Partner is required to devote only so much of its time as is necessary to manage the affairs of the Partnership. Except as expressly provided to the contrary in this Agreement, and subject to fiduciary duties, the Managing General Partner, the Operator, and their Affiliates may do the following: (i) continue their activities, or initiate further such activities, individually, jointly with others, or as a part of any other limited or general partnership, tax partnership, joint venture, or other entity or activity to which they are or may become a party, in any locale and in the same fields, areas of operation or prospects in which the Partnership may likewise be active; (ii) reserve partial interests in Leases being assigned to the Partnership or any other interests not expressly prohibited by this Agreement; (iii) deal with the Partnership as independent parties or through any other entity in which they may be interested; (iv) conduct business with the Partnership as set forth in this Agreement; and (v) participate in such other investor operations, as investors or otherwise. The Managing General Partner and its Affiliates shall not be required to permit the Partnership or the Participants to participate in any of the operations in which the Managing General Partner and its Affiliates may be interested or share in any profits or other benefits from the operations. However, except as otherwise provided in this Agreement, the Managing General Partner and its Affiliates may pursue business opportunities that are consistent with the Partnership's investment objectives for their own account only after they have determined that the opportunity either: 35 (i) cannot be pursued by the Partnership because of insufficient funds; or (ii) it is not appropriate for the Partnership under the existing circumstances. 4.06(b). Managing General Partner May Manage Multiple Partnerships. The Managing General Partner or its Affiliates may manage multiple Programs simultaneously. 4.06(c). Partnership Has No Interest in Natural Gas Contracts or Pipelines and Gathering Systems. Notwithstanding any other provision in this Agreement, the Partnership shall not: (i) be a party to any natural gas supply agreement that the Managing General Partner, the Operator, or their Affiliates enter into with a third-party or have any rights pursuant to such natural gas supply agreement; or (ii) receive any interest in the Managing General Partner's, the Operator's, and their Affiliates' pipeline or gathering system or compression facilities. ARTICLE V PARTICIPATION IN COSTS AND REVENUES, CAPITAL ACCOUNTS, ELECTIONS AND DISTRIBUTIONS 5.01. Participation in Costs and Revenues. Except as otherwise provided in this Agreement, costs and revenues shall be charged and credited to the Managing General Partner and the Participants as set forth in this section and its subsections. 5.01(a). Costs. Costs shall be charged as set forth below. 5.01(a)(1). Organization and Offering Costs. Organization and Offering Costs shall be charged 100% to the Managing General Partner. For purposes of sharing in revenues under ss.5.01(b)(4), the Managing General Partner shall be credited with Organization and Offering Costs paid by it and for services provided by it as Organization Costs up to and including 15% of the Partnership's subscription proceeds. Any Organization and Offering Costs paid and/or provided in services by the Managing General Partner in excess of this amount shall not be credited towards the Managing General Partner's required Capital Contribution or revenue share as set forth in ss.5.01(b)(4). The Managing General Partner's credit for services provided to the Partnership as Organization Costs shall be determined based on generally accepted accounting principles. 5.01(a)(2). Intangible Drilling Costs. Intangible Drilling Costs shall be charged 100% to the Participants. 5.01(a)(3). Tangible Costs. Tangible Costs shall be charged 66% to the Managing General Partner and 34% to the Participants. However, if the total Tangible Costs for all of the Partnership's wells that would be charged to the Participants exceeds an amount equal to 10% of the Partnership's subscription proceeds, then the excess shall be charged to the Managing General Partner. 5.01(a)(4). Operating Costs, Direct Costs, Administrative Costs and All Other Costs. Operating Costs, Direct Costs, Administrative Costs, and all other Partnership costs not specifically allocated shall be charged to the parties in the same ratio as the related production revenues are being credited. 5.01(a)(5). Allocation of Intangible Drilling Costs and Tangible Costs at Partnership Closings. Intangible Drilling Costs and the Participants' share of Tangible Costs of a well or wells to be drilled and completed with the proceeds of a Partnership closing shall be charged 100% to the Participants who are admitted to the Partnership in that closing and shall not be reallocated to take into account other Partnership closings. Although the proceeds of each Partnership closing will be used to pay the costs of drilling different wells, not less than 90% of each Participant's subscription proceeds shall be applied to Intangible Drilling Costs and not more than 10% of each Participant's subscription proceeds shall be applied to Tangible Costs regardless of when he subscribes. 36 5.01(a)(6). Lease Costs. The Leases shall be contributed to the Partnership by the Managing General Partner as set forth in ss.4.01(a)(4). 5.01(b). Revenues. Revenues shall be credited as set forth below. 5.01(b)(1). Allocation of Revenues on Disposition of Property. If the parties' Capital Accounts are adjusted to reflect the simulated depletion of a natural gas or oil property of the Partnership, then the portion of the total amount realized by the Partnership on the taxable disposition of the property that represents recovery of its simulated tax basis in the property shall be allocated to the parties in the same proportion as the aggregate adjusted tax basis of the property was allocated to the parties or their predecessors in interest. If the parties' Capital Accounts are adjusted to reflect the actual depletion of a natural gas or oil property of the Partnership, then the portion of the total amount realized by the Partnership on the taxable disposition of the property that equals the parties' aggregate remaining adjusted tax basis in the property shall be allocated to the parties in proportion to their respective remaining adjusted tax bases in the property. Thereafter, any excess shall be allocated to the Managing General Partner in an amount equal to the difference between the fair market value of the Lease at the time it was contributed to the Partnership and its simulated or actual adjusted tax basis at that time. Finally, any excess shall be credited as provided in ss.5.01(b)(4), below. In the event of a sale of developed natural gas and oil properties with equipment on the properties, the Managing General Partner may make any reasonable allocation of proceeds between the equipment and the Leases. 5.01(b)(2). Interest. Interest earned on each Participant's subscription proceeds before the Offering Termination Date under ss.3.05(b)(1) shall be credited to the accounts of the respective subscribers who paid the subscription proceeds to the Partnership. The interest shall be paid to the Participant not later than the Partnership's first cash distribution from operations. After the Offering Termination Date and until proceeds from the offering are invested in the Partnership's natural gas and oil operations, any interest income from temporary investments shall be allocated pro rata to the Participants providing the subscription proceeds. All other interest income, including interest earned on the deposit of production revenues, shall be credited as provided in ss.5.01(b)(4), below. 5.01(b)(3). Sale or Disposition of Equipment. Proceeds from the sale or disposition of equipment shall be credited to the parties charged with the costs of the equipment in the ratio in which the costs were charged. 5.01(b)(4). Other Revenues. Subject to ss.5.01(b)(4)(a), the Managing General Partner and the Participants shall share in all other Partnership revenues in the same percentage as their respective Capital Contribution bears to the total Partnership Capital Contributions, except that the Managing General Partner shall receive an additional 7% of Partnership revenues. However, the Managing General Partner's total revenue share may not exceed 35% of Partnership revenues. For example, if the Managing General Partner contributes 25% of the total Partnership Capital Contributions and the Participants contribute 75% of the total Partnership Capital Contributions, then the Managing General Partner shall receive 32% of the Partnership revenues and the Participants shall receive 68% of the Partnership revenues. On the other hand, if the Managing General Partner contributes 30% of the total Partnership Capital Contributions and the Participants contribute 70% of the total Partnership Capital Contributions, then the Managing General Partner shall receive 35% of the Partnership revenues, not 37%, because its revenue share cannot exceed 35% of Partnership revenues, and the Participants shall receive 65% of Partnership revenues. 5.01(b)(4)(a). Subordination. The Managing General Partner shall subordinate up to 50% of its share of Partnership Net Production Revenues to the receipt by Participants of cash distributions from the Partnership equal to $1,000 per Unit (which is 10% per Unit) regardless of their actual subscription price of the Units, in each of the first five 12-month periods beginning with the Partnership's first cash distributions from operations. In this regard: (i) the 60-month subordination period shall begin with the first cash distribution from operations to the Participants, but no subordination distributions to the Participants shall be required until the Partnership's first cash distribution to the Participants after substantially all Partnership wells have been drilled, completed, and placed in production in a sales line; 37 (ii) subsequent subordination distributions, if any, shall be determined and made at the time of each subsequent distribution of revenues to the Participants; and (iii) the Managing General Partner shall not subordinate more than 50% of its share of Partnership Net Production Revenues in any subordination period. The subordination shall be determined by: (i) carrying forward to subsequent 12-month periods the amount, if any, by which cumulative cash distributions to Participants, including any subordination payments, are less than: (a) $1,000 per Unit (10% per Unit) in the first 12-month period; (b) $2,000 per Unit (20% per Unit) in the second 12-month period; (c) $3,000 per Unit (30% per Unit) in the third 12-month period; or (d) $4,000 per Unit (40% per Unit) in the fourth 12-month period (no carry forward is required if such distributions are less than $5,000 per Unit (50% per Unit) in the fifth 12-month period because the Managing General Partner's subordination obligation terminates on the expiration of the fifth 12-month period); and (ii) reimbursing the Managing General Partner for any previous subordination payments to the extent cumulative cash distributions to Participants, including any subordination payments, would exceed: (a) $1,000 per Unit (10% per Unit) in the first 12-month period; (b) $2,000 per Unit (20% per Unit) in the second 12-month period; (c) $3,000 per Unit (30% per Unit) in the third 12-month period; (d) $4,000 per Unit (40% per Unit) in the fourth 12-month period; or (e) $5,000 per Unit (50% per Unit) in the fifth 12-month period. The Managing General Partner's subordination obligation shall be further subject to the following conditions: (i) the subordination obligation may be prorated in the Managing General Partner's discretion (e.g. in the case of a quarterly distribution, the Managing General Partner will not have any subordination obligation if the distributions to Participants equal $250 per Unit (25% of $1,000 per Unit per year) or more assuming there is no subordination owed for any preceding period); (ii) the Managing General Partner shall not be required to return Partnership distributions previously received by it, even though a subordination obligation arises after the distributions; (iii) subject to the foregoing provisions of this section, only Partnership revenues in the current distribution period shall be debited or credited to the Managing General Partner as may be necessary to provide, to the extent possible, subordination distributions to the Participants and reimbursements to the Managing General Partner; (iv) no subordination payments to the Participants or reimbursements to the Managing General Partner shall be made after the expiration of the fifth 12-month subordination period; and 38 (v) subordination payments to the Participants shall be subject to any lien or priority required by the Managing General Partner's lenders pursuant to agreements previously entered into or subsequently entered into or renewed by the Managing General Partner. 5.01(b)(5). Commingling of Revenues From All Partnership Wells. The revenues from all Partnership wells will be commingled, so regardless of when a Participant subscribes he will share in the revenues from all wells on the same basis as the other Participants. 5.01(c). Allocations. 5.01(c)(1). Allocations among Participants. Except as provided otherwise in this Agreement, costs (other than Intangible Drilling Costs and Tangible Costs) and revenues charged or credited to the Participants as a group, which includes all revenue credited to the Participants under ss.5.01(b)(4), shall be allocated among the Participants, including the Managing General Partner to the extent of any optional subscription under ss.3.03(b)(2), in the ratio of their respective Units based on $10,000 per Unit regardless of the actual subscription price for a Participant's Units. Intangible Drilling Costs and Tangible Costs charged to the Participants as a group shall be allocated among the Participants, including the Managing General Partner to the extent of any optional subscription under ss.3.03(b)(2), in the ratio of the subscription price designated on their respective Subscription Agreements rather than the number of their respective Units. 5.01(c)(2). Costs and Revenues Not Directly Allocable to a Partnership Well. Costs and revenues not directly allocable to a particular Partnership Well or additional operation shall be allocated among the Partnership Wells or additional operations in any manner the Managing General Partner in its reasonable discretion, shall select, and shall then be charged or credited in the same manner as costs or revenues directly applicable to the Partnership Well or additional operation are being charged or credited. 5.01(c)(3). Managing General Partner's Discretion in Making Allocations For Federal Income Tax Purposes. In determining the proper method of allocating charges or credits among the parties, or in making any other allocations under this Agreement, the Managing General Partner may adopt any method of allocation which it, in its reasonable discretion, selects, if, in its sole discretion based on advice from its legal counsel or accountants, a revision to the allocations is required for the allocations to be recognized for federal income tax purposes either because of the promulgation of Treasury Regulations or other developments in the tax law. Any new allocation provisions shall be provided by an amendment to this Agreement and shall be made in a manner that would result in the most favorable aggregate consequences to the Participants as nearly as possible consistent with the original allocations described in this Agreement. 5.02. Capital Accounts and Allocations Thereto. 5.02(a). Capital Accounts for Each Party to the Agreement. A single, separate Capital Account shall be established for each party, regardless of the number of interests owned by the party, the class of the interests and the time or manner in which the interests were acquired. 5.02(b). Charges and Credits. 5.02(b)(1). General Standard. Except as otherwise provided in this Agreement, the Capital Account of each party shall be determined and maintained in accordance with Treas. Reg. ss.1.704-l(b)(2)(iv) and shall be increased by: (i) the amount of money contributed by him to the Partnership; (ii) the fair market value of property contributed by him, without regard to ss.7701(g) of the Code, to the Partnership, net of liabilities secured by the contributed property that the Partnership is considered to assume or take subject to under ss.752 of the Code; and 39 (iii) allocations to him of Partnership income and gain, or items thereof, including income and gain exempt from tax and income and gain described in Treas. Reg. ss.1.704-l(b)(2)(iv)(g), but excluding income and gain described in Treas. Reg. ss.1.704- l(b)(4)(i); and shall be decreased by: (iv) the amount of money distributed to him by the Partnership; (v) the fair market value of property distributed to him, without regard to ss.7701(g) of the Code, by the Partnership, net of liabilities secured by the distributed property that he is considered to assume or take subject to under ss.752 of the Code; (vi) allocations to him of Partnership expenditures described in ss.705(a)(2)(B) of the Code; and (vii) allocations to him of Partnership loss and deduction, or items thereof, including loss and deduction described in Treas. Reg. ss.1.704-l(b)(2)(iv)(g), but excluding items described in (vi) above, and loss or deduction described in Treas. Reg. ss.1.704- l(b)(4)(i) or (iii). 5.02(b)(2). Exception. If Treas. Reg. ss.1.704-l(b)(2)(iv) fails to provide guidance, Capital Account adjustments shall be made in a manner that: (i) maintains equality between the aggregate governing Capital Accounts of the parties and the amount of Partnership capital reflected on the Partnership's balance sheet, as computed for book purposes; (ii) is consistent with the underlying economic arrangement of the parties; and (iii) is based, wherever practicable, on federal tax accounting principles. 5.02(c). Payments to the Managing General Partner. The Capital Account of the Managing General Partner shall be reduced by payments to it pursuant to ss.4.04(a)(2) only to the extent of the Managing General Partner's distributive share of any Partnership deduction, loss, or other downward Capital Account adjustment resulting from the payments. 5.02(d). Discretion of Managing General Partner in the Method of Maintaining Capital Accounts. Notwithstanding any other provisions of this Agreement, the method of maintaining Capital Accounts may be changed from time to time, in the discretion of the Managing General Partner, to take into consideration ss.704 and other provisions of the Code and the related rules, regulations and interpretations as may exist from time to time. 5.02(e). Revaluations of Property. In the discretion of the Managing General Partner the Capital Accounts of the parties may be increased or decreased to reflect a revaluation of Partnership property, including intangible assets such as goodwill, on a property-by-property basis except as otherwise permitted under ss.704(c) of the Code and the regulations thereunder, on the Partnership's books, in accordance with Treas. Reg. ss.1.704-l(b)(2)(iv)(f). 5.02(f). Amount of Book Items. In cases where ss.704(c) of the Code or ss.5.02(e) applies, Capital Accounts shall be adjusted in accordance with Treas. Reg. ss.1.704-l(b)(2)(iv)(g) for allocations of depreciation, depletion, amortization and gain and loss, as computed for book purposes, with respect to the property. 5.03. Allocation of Income, Deductions and Credits. 5.03(a). In General. 5.03(a)(1). Deductions Are Allocated to Party Charged with Expenditure. To the extent permitted by law and except as otherwise provided in this Agreement, all deductions and credits, including, but not limited to, intangible drilling and development costs and depreciation, shall be allocated to the party who has been charged with the expenditure giving rise to the deductions and credits; and to the extent permitted by law, these parties shall be entitled to the deductions and credits in computing taxable income or tax liabilities to the exclusion of any other party. Also, any Partnership deductions that would be 40 nonrecourse deductions if they were not attributable to a loan made or guaranteed by the Managing General Partner or its Affiliates shall be allocated to the Managing General Partner to the extent required by law. 5.03(a)(2). Income and Gain Allocated in Accordance With Revenues. Except as otherwise provided in this Agreement, all items of income and gain, including gain on disposition of assets, shall be allocated in accordance with the related revenue allocations set forth in ss.5.01(b) and its subsections. 5.03(b). Tax Basis of Each Property. Subject to ss.704(c) of the Code, the tax basis of each oil and gas property for computation of cost depletion and gain or loss on disposition shall be allocated and reallocated when necessary based on the capital interest in the Partnership as to the property and the capital interest in the Partnership for this purpose as to each property shall be considered to be owned by the parties in the ratio in which the expenditure giving rise to the tax basis of the property has been charged as of the end of the year. 5.03(c). Gain or Loss on Oil and Gas Properties. Each party shall separately compute its gain or loss on the disposition of each natural gas and oil property in accordance with the provisions of ss.613A(c)(7)D) of the Code, and the calculation of the gain or loss shall consider the party's adjusted basis in his property interest computed as provided in ss.5.03(b) and the party's allocable share of the amount realized from the disposition of the property. 5.03(d). Gain on Depreciable Property. Gain from each sale or other disposition of depreciable property shall be allocated to each party whose share of the proceeds from the sale or other disposition exceeds its contribution to the adjusted basis of the property in the ratio that the excess bears to the sum of the excesses of all parties having an excess. 5.03(e). Loss on Depreciable Property. Loss from each sale, abandonment or other disposition of depreciable property shall be allocated to each party whose contribution to the adjusted basis of the property exceeds its share of the proceeds from the sale, abandonment or other disposition in the proportion that the excess bears to the sum of the excesses of all parties having an excess. 5.03(f). Allocation If Recapture Treated As Ordinary Income. Any recapture treated as an increase in ordinary income by reason of ss.ss.1245, 1250, or 1254 of the Code shall be allocated to the parties in the amounts in which the recaptured items were previously allocated to them; provided that to the extent recapture allocated to any party is in excess of the party's gain from the disposition of the property, the excess shall be allocated to the other parties but only to the extent of the other parties' gain from the disposition of the property. 5.03(g). Tax Credits. As of the date of the Prospectus, tax credits are not available to the Partnership. If this changes in the future, however, and if a Partnership expenditure, whether or not deductible, that gives rise to a tax credit in a Partnership taxable year also gives rise to valid allocations of Partnership loss or deduction, or other downward Capital Account adjustments, for the year, then the parties' interests in the Partnership with respect to the credit, or the cost giving rise thereto, shall be in the same proportion as the parties' respective distributive shares of the loss or deduction, and adjustments. Identical principles shall apply in determining the parties' interests in the Partnership with respect to tax credits that arise from receipts of the Partnership, whether or not taxable. 5.03(h). Deficit Capital Accounts and Qualified Income Offset. Notwithstanding any provisions of this Agreement to the contrary, an allocation of loss or deduction which would result in a party having a deficit Capital Account balance as of the end of the taxable year to which the allocation relates, if charged to the party, to the extent the Participant is not required to restore the deficit to the Partnership, taking into account: (i) adjustments that, as of the end of the year, reasonably are expected to be made to the party's Capital Account for depletion allowances with respect to the Partnership's natural gas and oil properties; (ii) allocations of loss and deduction that, as of the end of the year, reasonably are expected to be made to the party under ss.ss.704(e)(2) and 706(d) of the Code and Treas. Reg. ss.1.751-1(b)(2)(ii); and 41 (iii) distributions that, as of the end of the year, reasonably are expected to be made to the party to the extent they exceed offsetting increases to the party's Capital Account, assuming for this purpose that the fair market value of Partnership property equals its adjusted tax basis, that reasonably are expected to occur during or prior to the Partnership taxable years in which the distributions reasonably are expected to be made; shall be charged to the Managing General Partner. Further, the Managing General Partner shall be credited with an additional amount of Partnership income or gain equal to the amount of the loss or deduction as quickly as possible to the extent such chargeback does not cause or increase deficit balances in the parties' Capital Accounts which are not required to be restored to the Partnership. Notwithstanding any provisions of this Agreement to the contrary, if a party unexpectedly receives an adjustment, allocation, or distribution described in (i), (ii), or (iii) above, or any other distribution, which causes or increases a deficit balance in the party's Capital Account which is not required to be restored to the Partnership, the party shall be allocated items of income and gain, consisting of a pro rata portion of each item of Partnership income, including gross income, and gain for the year, in an amount and manner sufficient to eliminate the deficit balance as quickly as possible. 5.03(i). Minimum Gain Chargeback. To the extent there is a net decrease during a Partnership taxable year in the minimum gain attributable to a Partner nonrecourse debt, then any Partner with a share of the minimum gain attributable to the debt at the beginning of the year shall be allocated items of Partnership income and gain in accordance with Treas. Reg. ss.1.704-2(i). 5.03(j). Partners' Allocable Shares. Except as otherwise provided in this Agreement, each party's allocable share of Partnership income, gain, loss, deductions and credits shall be determined by the use of any method prescribed or permitted by the Secretary of the Treasury by regulations or other guidelines and selected by the Managing General Partner which takes into account the varying interests of the parties in the Partnership during the taxable year. In the absence of such regulations or guidelines, except as otherwise provided in this Agreement, the allocable share shall be based on actual income, gain, loss, deductions and credits economically accrued each day during the taxable year in proportion to each party's varying interest in the Partnership on each day during the taxable year. 5.04. Elections. 5.04(a). Election to Deduct Intangible Costs. The Partnership's federal income tax return shall be made in accordance with an election under the option granted by the Code to deduct intangible drilling and development costs. 5.04(b). No Election Out of Subchapter K. No election shall be made by the Partnership, any Partner, or the Operator for the Partnership to be excluded from the application of the partnership provisions of Subchapter K of the Code. 5.04(c). Contingent Income. If it is determined that any taxable income results to any party by reason of its entitlement to a share of profits or revenues of the Partnership before the profit or revenue has been realized by the Partnership, the resulting deduction as well as any resulting gain, shall not enter into Partnership net income or loss but shall be separately allocated to the party. 5.04(d). ss.754 Election. In the event of the transfer of an interest in the Partnership, or on the death of an individual party hereto, or in the event of the distribution of property to any party, the Managing General Partner may choose for the Partnership to file an election in accordance with the applicable Treasury Regulations to cause the basis of the Partnership's assets to be adjusted for federal income tax purposes as provided by ss.ss.734 and 743 of the Code. 5.05. Distributions. 5.05(a). In General. 5.05(a)(1). Quarterly Review of Accounts. The Managing General Partner shall review the accounts of the Partnership at least quarterly to determine whether cash distributions are appropriate and the amount to be distributed, if any. 42 5.05(a)(2). Distributions. The Partnership shall distribute funds to the Managing General Partner and the Participants allocated to their accounts which the Managing General Partner deems unnecessary to retain by the Partnership. 5.05(a)(3). No Borrowings. In no event, however, shall funds be advanced or borrowed for distributions if the amount of the distributions would exceed the Partnership's accrued and received revenues for the previous four quarters, less paid and accrued Operating Costs with respect to the revenues. The determination of revenues and costs shall be made in accordance with generally accepted accounting principles, consistently applied. 5.05(a)(4). Distributions to the Managing General Partner. Cash distributions from the Partnership to the Managing General Partner shall only be made as follows: (a) in conjunction with distributions to Participants; and (b) out of funds properly allocated to the Managing General Partner's account. 5.05(a)(5). Reserve. At any time after one year from the date each Partnership Well is placed into production, the Managing General Partner shall have the right to deduct each month from the Partnership's proceeds of the sale of the production from the well up to $200 for the purpose of establishing a fund to cover the estimated costs of plugging and abandoning the well. All of these funds shall be deposited in a separate interest bearing account for the benefit of the Partnership, and the total amount so retained and deposited shall not exceed the Managing General Partner's reasonable estimate of the costs. 5.05(b). Distribution of Uncommitted Subscription Proceeds. Any net subscription proceeds not expended or committed for expenditure, as evidenced by a written agreement, by the Partnership within 12 months of the Offering Termination Date, except necessary operating capital, shall be distributed to the Participants in the ratio that the subscription price designated on each Participant's Subscription Agreement bears to the total subscription prices designated on all of the Participants' Subscription Agreements, as a return of capital. The Managing General Partner shall reimburse the Participants for the selling or other offering expenses allocable to the return of capital. For purposes of this subsection, "committed for expenditure" shall mean contracted for, actually earmarked for or allocated by the Managing General Partner to the Partnership's drilling operations, and "necessary operating capital" shall mean those funds which, in the opinion of the Managing General Partner, should remain on hand to assure continuing operation of the Partnership. 5.05(c). Distributions on Winding Up. On the winding up of the Partnership distributions shall be made as provided in ss.7.02. 5.05(d). Interest and Return of Capital. No party shall under any circumstances be entitled to any interest on amounts retained by the Partnership. Each Participant shall look only to his share of distributions, if any, from the Partnership for a return of his Capital Contribution. ARTICLE VI TRANSFER OF INTERESTS 6.01. Transferability. 6.01(a). Rights of Assignee. On a transfer unless an assignee becomes a substituted Participant in accordance with the provisions set forth below, he shall not be entitled to any of the rights granted to a Participant under this Agreement, other than the right to receive all or part of the share of the profits, losses, income, gain, credits and cash distributions or returns of capital to which his assignor would otherwise be entitled. 43 6.01(b). Conversion of Investor General Partner Units to Limited Partner Units. 6.01(b)(1). Automatic Conversion. After all of the Partnership Wells have been drilled and completed the Managing General Partner shall file an amended certificate of limited partnership with the Secretary of State of the State of Delaware for the purpose of converting the Investor General Partner Units to Limited Partner Units. 6.01(b)(2). Investor General Partners Shall Have Contingent Liability. On conversion the Investor General Partners shall be Limited Partners entitled to limited liability; however, they shall remain liable to the Partnership for any additional Capital Contribution required for their proportionate share of any Partnership obligation or liability arising before the conversion of their Units as provided in ss.3.05(b)(2). 6.01(b)(3). Conversion Shall Not Affect Allocations. The conversion shall not affect the allocation to any Participant of any item of Partnership income, gain, loss, deduction or credit or other item of special tax significance other than Partnership liabilities, if any. Further, the conversion shall not affect any Participant's interest in the Partnership's natural gas and oil properties and unrealized receivables. 6.01(b)(4). Right to Convert if Reduction of Insurance. Notwithstanding the foregoing, the Managing General Partner shall notify all Participants at least 30 days before the effective date of any adverse material change in the Partnership's insurance coverage. If the insurance coverage is to be materially reduced, then the Investor General Partners shall have the right to convert their Units into Limited Partner Units before the reduction by giving written notice to the Managing General Partner. 6.02. Special Restrictions on Transfers. 6.02(a). In General. Transfers are subject to the following general conditions: (i) only whole Units may be assigned unless the Participant owns less than a whole Unit, in which case his entire fractional interest must be assigned; (ii) the costs and expenses associated with the assignment must be paid by the assignor Participant; (iii) the assignment must be in a form satisfactory to the Managing General Partner; and (iv) the terms of the assignment must not contravene those of this Agreement. Transfers of Units are subject to the following additional restrictions set forth in ss.ss.6.02(a)(1) and 6.02(a)(2). 6.02(a)(1). Tax Law Restrictions. Subject to transfers permitted by ss.6.04 and transfers by operation of law, no sale, assignment, exchange, or transfer of a Unit shall be made which, in the opinion of counsel to the Partnership, would result in the Partnership being either: (i) terminated for tax purposes under ss.708 of the Code; or (ii) treated as a "publicly-traded" partnership for purposes of ss.469(k) of the Code. 6.02(a)(2). Securities Laws Restriction. Subject to transfers permitted by ss.6.04 and transfers by operation of law, no Unit shall be sold, assigned, pledged, hypothecated, or transferred which, in the opinion of counsel to the Partnership, would result in the violation of any applicable federal or state securities laws. Transfers are also subject to any conditions contained in the Subscription Agreement and Exhibit (B) to the Prospectus. 44 6.02(a)(3). Substitute Participant. 6.02(a)(3)(a). Procedure to Become Substitute Participant. Subject to ss.ss.6.02(a)(1) and 6.02(a)(2), an assignee of a Participant's Unit shall become a substituted Participant entitled to all the rights of a Participant if, and only if: (i) the assignor gives the assignee the right; (ii) the assignee pays to the Partnership all costs and expenses incurred in connection with the substitution; and (iii) the assignee executes and delivers the instruments necessary to establish that a legal transfer has taken place and to confirm the agreement of the assignee to be bound by all of the terms of this Agreement. 6.02(a)(3)(b). Rights of Substitute Participant. A substitute Participant is entitled to all of the rights attributable to full ownership of the assigned Units including the right to vote. 6.02(b). Effect of Transfer. 6.02(b)(1). Amendment of Records. The Partnership shall amend its records at least once each calendar quarter to effect the substitution of substituted Participants. Any transfer permitted under this Agreement when the assignee does not become a substituted Participant shall be effective as follows: (i) midnight of the last day of the calendar month in which it is made; or (ii) at the Managing General Partner's election, 7:00 A.M. of the following day. 6.02(b)(2). Transfer Does Not Relieve Transferor of Certain Costs. No transfer, including a transfer of less than all of a Participant's Units or the transfer of Units to more than one party, shall relieve the transferor of its responsibility for its proportionate part of any expenses, obligations and liabilities under this Agreement related to the Units so transferred, whether arising before or after the transfer. 6.02(b)(3). Transfer Does Not Require An Accounting. No transfer of a Unit shall require an accounting by the Managing General Partner. Also, no transfer shall grant rights under this Agreement, including the exercise of any elections, as between the transferring parties and the remaining parties to this Agreement to more than one party unanimously designated by the transferees and, if he should have retained an interest under this Agreement, the transferor. 6.02(b)(4). Notice. Until the Managing General Partner receives a proper notice of designation acceptable to it, the Managing General Partner shall continue to account only to the person to whom it was furnishing notices before the time pursuant to ss.8.01 and its subsections. This party shall continue to exercise all rights applicable to the Units previously owned by the transferor. 6.03. Right of Managing General Partner to Hypothecate and/or Withdraw Its Interests. The Managing General Partner shall have the authority without the consent of the Participants and without affecting the allocation of costs and revenues received or incurred under this Agreement, to hypothecate, pledge, or otherwise encumber, on any terms it chooses for its own general purposes either: (i) its Partnership interest; or (ii) an undivided interest in the assets of the Partnership equal to or less than its respective interest in the revenues of the Partnership. 45 All repayments of these borrowings and costs, interest or other charges related to the borrowings shall be borne and paid separately by the Managing General Partner. In no event shall the repayments, costs, interest, or other charges related to the borrowing be charged to the account of the Participants. In addition, subject to a required participation of not less than 1% in the Partnership as Managing General Partner, the Managing General Partner may withdraw a property interest held by the Partnership in the form of a Working Interest in the Partnership Wells equal to or less than its respective interest in the revenues of the Partnership if: (i) the withdrawal is necessary to satisfy the bona fide request of its creditors; or (ii) the withdrawal is approved by Participants whose Units equal a majority of the total Units. 6.04. Presentment. 6.04(a). In General. Participants shall have the right to present their interests to the Managing General Partner for purchase subject to the conditions and limitations set forth in this section. A Participant, however, is not obligated to present his Units for purchase. The Managing General Partner shall not be obligated to purchase more than 5% of the Units in any calendar year and this 5% limit may not be waived. The Managing General Partner shall not purchase less than one Unit unless the lesser amount represents the Participant's entire interest in the Partnership, however, the Managing General Partner may waive this limitation. A Participant may present his Units in writing to the Managing General Partner every year beginning with the fifth calendar year after the Offering Termination Date subject to the following conditions: (i) the presentment must be made within 120 days of the reserve report set forth in ss.4.03(b)(3); (ii) in accordance with Treas. Reg. ss.1.7704-1(f), the purchase may not be made until at least 60 calendar days after the Participant notifies the Partnership in writing of the Participant's intention to exercise the presentment right; and (iii) the purchase shall not be considered effective until the presentment price has been paid in cash to the Participant. 6.04(b). Requirement for Independent Petroleum Consultant. The amount of the presentment price attributable to Partnership reserves shall be determined based on the last reserve report of the Partnership prepared by the Managing General Partner and reviewed by an Independent Expert. The Managing General Partner shall estimate the present worth of future net revenues attributable to the Partnership's interest in the Proved Reserves. In making this estimate, the Managing General Partner shall use the following terms: (i) a discount rate equal to 10%; (ii) a constant price for the oil; and (iii) base the price of natural gas on the existing natural gas contracts at the time of the purchase. The calculation of the presentment price shall be as set forth in ss.6.04(c). 6.04(c). Calculation of Presentment Price. The presentment price shall be based on the Participant's share of the net assets and liabilities of the Partnership and allocated pro rata to each Participant in the ratio that his number of Units bears to the total number of Units. The presentment price shall include the sum of the following Partnership items: 46 (i) an amount based on 70% of the present worth of future net revenues from the Proved Reserves determined as described in ss.6.04(b); (ii) cash on hand; (iii) prepaid expenses and accounts receivable less a reasonable amount for doubtful accounts; and (iv) the estimated market value of all assets, not separately specified above, determined in accordance with standard industry valuation procedures. There shall be deducted from the foregoing sum the following items: (i) an amount equal to all debts, obligations, and other liabilities, including accrued expenses; and (ii) any distributions made to the Participants between the date of the request and the actual payment. However, if any cash distributed was derived from the sale, after the presentment request, of natural gas, oil or other mineral production, or of a producing property owned by the Partnership, for purposes of determining the reduction of the presentment price, the distributions shall be discounted at the same rate used to take into account the risk factors employed to determine the present worth of the Partnership's Proved Reserves. 6.04(d). Further Adjustment May Be Allowed. The presentment price may be further adjusted by the Managing General Partner for estimated changes therein from the date of the report to the date of payment of the presentment price to the Participants because of the following: (i) the production or sales of, or additions to, reserves and lease and well equipment, sale or abandonment of Leases, and similar matters occurring before the request for purchase; and (ii) any of the following occurring before payment of the presentment price to the selling Participants: (a) changes in well performance; (b) increases or decreases in the market price of natural gas, oil or other minerals; (c) revision of regulations relating to the importing of hydrocarbons; (d) changes in income, ad valorem, and other tax laws such as material variations in the provisions for depletion; and (e) similar matters. 6.04(e). Selection by Lot. If less than all Units presented at any time are to be purchased, then the Participants whose Units are to be purchased will be selected by lot. The Managing General Partner's obligation to purchase Units presented may be discharged for its benefit by a third-party or an Affiliate. The Units of the selling Participant will be transferred to the party who pays for it. A selling Participant will be required to deliver an executed assignment of his Units, together with any other documentation as the Managing General Partner may reasonably request. 6.04(f). No Obligation of the Managing General Partner to Establish a Reserve. The Managing General Partner shall have no obligation to establish any reserve to satisfy the presentment obligations under this section. 6.04(g). Suspension of Presentment Feature. The Managing General Partner may suspend this presentment feature by so notifying Participants at any time if it: 47 (i) does not have sufficient cash flow; or (ii) is unable to borrow funds for this purpose on terms it deems reasonable. In addition, the presentment feature may be conditioned, in the Managing General Partner's sole discretion, on the Managing General Partner's receipt of an opinion of counsel that the transfers will not cause the Partnership to be treated as a "publicly traded partnership" under the Code. The Managing General Partner shall hold the purchased Units for its own account and not for resale. ARTICLE VII DURATION, DISSOLUTION, AND WINDING UP 7.01. Duration. 7.01(a). Fifty Year Term. The Partnership shall continue in existence for a term of 50 years from the effective date of this Agreement unless sooner terminated as set forth below. 7.01(b). Termination. The Partnership shall terminate following the occurrence of: (i) a Final Terminating Event; or (ii) any event which under the Delaware Revised Uniform Limited Partnership Act causes the dissolution of a limited partnership. 7.01(c). Continuance of Partnership Except on Final Terminating Event. Other than the occurrence of a Final Terminating Event, the Partnership or any successor limited partnership shall not be wound up, but shall be continued by the parties and their respective successors as a successor limited partnership under all the terms of this Agreement. The successor limited partnership shall succeed to all of the assets of the Partnership. As used throughout this Agreement, the term "Partnership" shall include the successor limited partnerships and the parties to the successor limited partnerships. 7.02. Dissolution and Winding Up. 7.02(a). Final Terminating Event. On the occurrence of a Final Terminating Event the affairs of the Partnership shall be wound up and there shall be distributed to each of the parties its Distribution Interest in the remaining Partnership assets. 7.02(b). Time of Liquidating Distribution. To the extent practicable and in accordance with sound business practices in the judgment of the Managing General Partner, liquidating distributions shall be made by: (i) the end of the taxable year in which liquidation occurs, determined without regard to ss.706(c)(2)(A) of the Code; or (ii) if later, within 90 days after the date of the liquidation. Notwithstanding, the following amounts are not required to be distributed within the foregoing time periods so long as the withheld amounts are distributed as soon as practical: (i) amounts withheld for reserves reasonably required for liabilities of the Partnership; and (ii) installment obligations owed to the Partnership. 7.02(c). In-Kind Distributions. The Managing General Partner shall not be obligated to offer in-kind property distributions to the Participants, and shall do so, in its discretion. Any in-kind property distributions to the Participants shall be made to a liquidating trust or similar entity for the benefit of the Participants, unless at the time of the distribution: 48 (i) the Managing General Partner offers the individual Participants the election of receiving in-kind property distributions and the Participants accept the offer after being advised of the risks associated with direct ownership; or (ii) there are alternative arrangements in place which assure the Participants that they will not, at any time, be responsible for the operation or disposition of Partnership properties. If the Managing General Partner has not received a Participant's consent within 30 days after the Managing General Partner mailed the request for consent, then it shall be presumed that the Participant has refused his consent. 7.02(d). Sale If No Consent. Any Partnership asset which would otherwise be distributed in-kind to a Participant, except for the failure or refusal of the Participant to give his written consent to the distribution, may instead be sold by the Managing General Partner at the best price reasonably obtainable from an independent third-party, who is not an Affiliate of the Managing General Partner or to itself or its Affiliates, including an Affiliated Income Program, at fair market value as determined by an Independent Expert selected by the Managing General Partner. ARTICLE VIII MISCELLANEOUS PROVISIONS 8.01. Notices. 8.01(a). Method. Any notice required under this Agreement shall be: (i) in writing; and (ii) given by mail or wire addressed to the party to receive the notice at the address designated in ss.1.03. If there is a transfer of Units under this Agreement, no notice to the transferee shall be required, nor shall the transferee have any rights under this Agreement, until notice has been given to the Managing General Partner. Any transfer of rights under this Agreement shall not increase the duty to give notice. If there is a transfer of Units under this Agreement to more than one party, then notice to any owner of any interest in the Units shall be notice to all owners of the Units. 8.01(b). Change in Address. The address of any party to this Agreement may be changed by written notice as follows: (i) to the Participants if there is a change of address by the Managing General Partner; or (ii) to the Managing General Partner if there is a change of address by a Participant. 8.01(c). Time Notice Deemed Given. If the notice is given by the Managing General Partner, then the notice shall be considered given, and any applicable time shall run, from the date the notice is placed in the mail or delivered to the telegraph company. If the notice is given by any Participant, then the notice shall be considered given and any applicable time shall run from the date the notice is received. 8.01(d). Effectiveness of Notice. Any notice to a party other than the Managing General Partner, including a notice requiring concurrence or nonconcurrence, shall be effective, and any failure to respond binding, irrespective of the following: (i) whether or not the notice is actually received; or (ii) any disability or death on the part of the noticee, even if the disability or death is known to the party giving the notice. 8.01(e). Failure to Respond. Except pursuant to ss.7.02(c) or when this Agreement expressly requires affirmative approval of a Participant, any Participant who fails to respond in writing within the time specified to a request by the Managing General 49 Partner as set forth below, for approval of or concurrence in a proposed action shall be conclusively deemed to have approved the action. The Managing General Partner shall send the first request and the time period shall be not less than 15 business days from the date of mailing of the request. If the Participant does not respond to the first request, then the Managing General Partner shall send a second request. If the Participant does not respond within seven calendar days from the date of the mailing of the second request, then the Participant shall be conclusively deemed to have approved the action. 8.02. Time. Time is of the essence of each part of this Agreement. 8.03. Applicable Law. The terms and provisions of this Agreement shall be construed under the laws of the State of Delaware, provided, however, this section shall not be deemed to limit causes of action for violations of federal or state securities law to the laws of the State of Delaware. Neither this Agreement nor the Subscription Agreement shall require mandatory venue or mandatory arbitration of any or all claims by Participants against the Sponsor. 8.04. Agreement in Counterparts. This Agreement may be executed in counterpart and shall be binding on all parties executing this or similar agreements from and after the date of execution by each party. 8.05. Amendment. 8.05(a). Procedure for Amendment. No changes in this Agreement shall be binding unless: (i) proposed in writing by the Managing General Partner, and adopted with the consent of Participants whose Units equal a majority of the total Units; or (ii) proposed in writing by Participants whose Units equal 10% or more of the total Units and approved by an affirmative vote of Participants whose Units equal a majority of the total Units. 8.05(b). Circumstances Under Which the Managing General Partner Alone May Amend. The Managing General Partner is authorized to amend this Agreement and its exhibits without the consent of Participants in any way deemed necessary or desirable by it to: (i) add or substitute in the case of an assigning party additional Participants; (ii) enhance the tax benefits of the Partnership to the parties; or (iii) satisfy any requirements, conditions, guidelines, options, or elections contained in any opinion, directive, order, ruling, or regulation of the SEC, the IRS, or any other federal or state agency, or in any federal or state statute, compliance with which it deems to be in the best interest of the Partnership. Notwithstanding the foregoing, no amendment materially and adversely affecting the interests or rights of Participants shall be made without the consent of the Participants whose interests will be so affected. 8.06. Additional Partners. Each Participant hereby consents to the admission to the Partnership of additional Participants as the Managing General Partner, in its discretion, chooses to admit. 8.07. Legal Effect. This Agreement shall be binding on and inure to the benefit of the parties, their heirs, devisees, personal representatives, successors and assigns, and shall run with the interests subject to this Agreement. The terms "Partnership," "Limited Partner," "Investor General Partner," "Participant," "Partner," "Managing General Partner," "Operator," or "parties" shall equally apply to any successor limited partnership, and any heir, devisee, personal representative, successor or assign of a party. IN WITNESS WHEREOF, the parties hereto set their hands as of the day and year hereinabove shown. ATLAS: ATLAS RESOURCES, INC. Managing General Partner By: _____________________________________ 50 EXHIBIT (I-A) FORM OF MANAGING GENERAL PARTNER SIGNATURE PAGE EXHIBIT (I-A) MANAGING GENERAL PARTNER SIGNATURE PAGE Attached to and made a part of the AMENDED AND RESTATED CERTIFICATE AND AGREEMENT OF LIMITED PARTNERSHIP of ATLAS AMERICA PUBLIC #12-2003 LIMITED PARTNERSHIP The undersigned agrees: 1. to serve as the Managing General Partner of ATLAS AMERICA PUBLIC #12- 2003 LIMITED PARTNERSHIP (the "Partnership"), and hereby executes, swears to, and agrees to all the terms of the Partnership Agreement; 2. to pay the required subscription of the Managing General Partner under ss.3.03(b)(1) of the Partnership Agreement; and 3. to subscribe to the Partnership as follows: (a) $_________________ [________] Unit(s)] under Section 3.03(b)(2) of the Partnership Agreement as a Limited Partner; or (b) $_________________ [________] Unit(s)] under Section 3.03(b)(2) of the Partnership Agreement as an Investor General Partner. Managing General Partner:
Atlas Resources, Inc. Address: By: ______________________________________ 311 Rouser Road Moon Township, Pennsylvania 15108 ACCEPTED this ________ day of_______________ , 200___. ATLAS RESOURCES, INC. MANAGING GENERAL PARTNER By: ____________________________
EXHIBIT (I-B) FORM OF SUBSCRIPTION AGREEMENT ATLAS AMERICA PUBLlC #12-2003 LIMITED PARTNERSHIP - ------------------------------------------------------------------------------- SUBSCRIPTION AGREEMENT - ------------------------------------------------------------------------------- I, the undersigned, hereby offer to purchase Units of Atlas America Public #12-2003 Limited Partnership in the amount set forth on the Signature Page of this Subscription Agreement and on the terms described in the current Prospectus for Atlas America Public #12-2003 Program, as supplemented or amended from time to time. I acknowledge and agree that my execution of this Subscription Agreement also constitutes my execution of the Agreement of Limited Partnership (the "Partnership Agreement") the form of which is attached as Exhibit (A) to the Prospectus and I agree to be bound by all of the terms and conditions of the Partnership Agreement if my subscription is accepted by Atlas Resources, Inc., the Managing General Partner. I understand and agree that I may not assign this offer, nor may it be withdrawn after it has been accepted by the Managing General Partner. I hereby irrevocably constitute and appoint the Managing General Partner, and its duly authorized agents, my agent and attorney-in-fact, in my name, place and stead, to make, execute, acknowledge, swear to, file, record and deliver the Agreement of Limited Partnership and any certificates related thereto. In order to induce the Managing General Partner to accept this subscription, I hereby represent, warrant, covenant and agree as follows:
Investor's Co-Investor's Initials Initials _____ _____ I have received the Prospectus. _____ _____ I, other than if I am a Minnesota or Maine resident, recognize and understand that: o before this offering there has been no public market for the Units and it is unlikely that after the offering there will be any such market; o the transferability of the Units is restricted; and o in case of emergency or other change in circumstances I cannot expect to be able to readily liquidate my investment in the Units. _____ _____ I am purchasing the Units for the following: o my own account; o for investment purposes and not for the account of others; and o with no present intention of reselling them. _____ _____ If an individual, I am: o a citizen of the United States of America; and o at least twenty-one years of age. _____ _____ If a partnership, corporation or trust, then the members, stockholders or beneficiaries thereof are citizens of the United States. I am at least twenty-one years of age and empowered and duly authorized under a governing document, trust instrument, charter, certificate of incorporation, by-law provision or the like to enter into this Subscription Agreement and to perform the transactions contemplated by the Prospectus, including its exhibits. (a) I have either: _____ _____ o a net worth of at least $225,000, exclusive of home, furnishings and automobiles; or
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Investor's Co-Investor's Initials Initials _____ _____ o a net worth, exclusive of home, furnishings and automobiles, of: o at least $60,000; and o had during the last tax year, or estimate that I will have during the current tax year, "taxable income" as defined in Section 63 of the Code of at least $60,000, without regard to an investment in the Partnership. _____ _____ (b) In addition, if I am a resident of: o Alabama, o Michigan, o Oregon, o Arizona, o Minnesota, o Pennsylvania, o California, o Mississippi, o South Dakota, o Indiana, o Missouri, o Tennessee, o Iowa, o New Hampshire, o Texas, o Kansas, o New Mexico, o Vermont or o Kentucky, o North Carolina, o Washington, o Maine, o Ohio, o Massachusetts, o Oklahoma, then I represent that I am aware of and meet that state's qualifications and suitability standards set forth in Exhibit (B) to the Prospectus. _____ _____ (c) If I am a fiduciary, then I am purchasing for a person or entity having the appropriate income and/or net worth specified in (a) or (b) above. _____ _____ I, other than if I am a Minnesota or Maine resident, understand that if I am an Investor General Partner, then I will have unlimited joint and several liability for Partnership obligations and liabilities including amounts in excess of my subscription to the extent the obligations and liabilities exceed the following: o the Partnership's insurance proceeds; o the Partnership's assets; and o indemnification by the Managing General Partner. Insurance may be inadequate to cover these liabilities and there is no insurance coverage for certain claims. _____ _____ I, other than if I am a Minnesota or Maine resident, understand that if I am a Limited Partner, then I may only use my Partnership losses to the extent of my net passive income from passive activities in the year, with any excess losses being deferred. _____ _____ I, other than if I am a Minnesota or Maine resident, understand that no state or federal governmental authority has made any finding or determination relating to the fairness for public investment of the Units and no state or federal governmental authority has recommended or endorsed or will recommend or endorse the Units. _____ _____ I, other than if I am a Minnesota or Maine resident, understand that the Selling Agent or registered representative is required to inform me and the other potential investors of all pertinent facts relating to the Units, including the following:
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Investor's Co-Investor's Initials Initials o the risks involved in the offering, including the speculative nature of the investment and the speculative nature of drilling for natural gas and oil; o the financial hazards involved in the offering, including the risk of losing my entire investment; o the lack of liquidity of my investment; o the restrictions on transferability of my Units; o the background of the Managing General Partner and the Operator; o the tax consequences of my investment; and o the unlimited joint and several liability of the Investor General Partners.
The above representations do not constitute a waiver of any rights that I may have under the Acts administered by the SEC or by any state regulatory agency administering statutes bearing on the sale of securities. Instructions to Investor You are required to execute your own Subscription Agreement and the Managing General Partner will not accept any Subscription Agreement that has been executed by someone other than you unless: o the person has been given your legal power of attorney to sign on your behalf; and o you meet all of the conditions in the Prospectus and this Subscription Agreement. In the case of sales to fiduciary accounts, the minimum standards set forth in the Prospectus and this Subscription Agreement must be met by: o the beneficiary; o the fiduciary account; or o by the donor or grantor who directly or indirectly supplies the funds to purchase the Partnership Units if the donor or grantor is the fiduciary. Your execution of the Subscription Agreement constitutes your binding offer to buy Units in the Partnership. Once you subscribe you may withdraw your subscription only by providing the Managing General Partner with written notice of your withdrawal before your subscription is accepted by the Managing General Partner. The Managing General Partner has the discretion to refuse to accept your subscription without liability to you. Subscriptions will be accepted or rejected by the Partnership within 30 days of their receipt. If your subscription is rejected, then all of your funds will be returned to you immediately. If your subscription is accepted before the first closing, then you will be admitted as a Participant not later than 15 days after the release from escrow of the investors' funds to the Partnership. If your subscription is accepted after the first closing, then you will be admitted into the Partnership not later than the last day of the calendar month in which your subscription was accepted by the Partnership. The Managing General Partner will do the following: o not complete a sale of Units to you until at least five business days after the date you receive a final Prospectus; and o send you a confirmation of purchase. NOTICE TO CALIFORNIA RESIDENTS: This offering deviates in certain respects from various requirements of Title 10 of the California Administrative Code. These deviations include, but are not limited to the following: the definition of Prospect in the Prospectus, unlike Rule 260.140.127.2(b) and Rule 260.140.121(1), does not require enlarging or contracting the size of the area on the basis of geological data in all cases. If a resident of California I acknowledge the receipt of California Rule 260.141.11 set forth in Exhibit (B) to the Prospectus. 3 - ------------------------------------------------------------------------------- SIGNATURE PAGE OF SUBSCRIPTION AGREEMENT - ------------------------------------------------------------------------------- I, the undersigned, agree to purchase ________ Units at $10,000 per Unit in ATLAS AMERICA PUBLIC #12-2003 LIMITED PARTNERSHIP (the "Partnership") as (check one):
| | INVESTOR GENERAL PARTNER | | LIMITED PARTNER Subscription Price $ --------------------------- (_____________________# Units)
Instructions - ------------------------------------------------------------------------------- Make your check payable to: "Atlas America Public #12-2003 Limited Partnership, Escrow Agent, National City Bank of PA" Minimum Subscription: one Unit ($10,000), however, the Managing General Partner, in its discretion, may accept one-half Unit ($5,000) subscriptions. Additional Subscriptions in $1,000 increments. If you are an individual investor you must personally sign this signature page and provide the information requested below. - -------------------------------------------------------------------------------
Subscriber (All individual My Home Address (Do not use P.O. Box) investors must personally sign this Signature Page.) - ------------------------------------- ------------------------------------- Print Name - ------------------------------------- ------------------------------------- Signature - ------------------------------------- ------------------------------------- Print Name My Address for Distributions if Different from Above - ------------------------------------- ------------------------------------- Signature Date:--------------- My Tax I.D. No. (Social Security No.): ------------- Account No.: ----------------------- My Telephone No.: Business --------- Home -------------------------------- My E-mail Address:-------------------------------
(CHECK ONE): I am a: | | Calendar Year Taxpayer | | Fiscal Year Taxpayer (CHECK IF APPLICABLE): I am a: | | Farmer (2/3 or more of my gross income in 2003 or 2002 is from farming) (CHECK ONE): OWNERSHIP OF THE UNITS- | | Tenants-in-Common | | Partnership | | Joint Tenancy | | C Corporation | | Individual | | S Corporation | | Trust | | Community Property | | Limited Liability Company | | Other
NAME OF TRUST, CORPORATION, LLC, PARTNERSHIP: Name ----------------------- (Enclose supporting documents.) 1 - ------------------------------------------------------------------------------- TO BE COMPLETED BY REGISTERED REPRESENTATIVE (For Commission and Other Purposes) - ------------------------------------------------------------------------------- I hereby represent that I have discharged my affirmative obligations under Rule 2810(b)(2)(B) and (b)(3)(D) of the NASD's Conduct Rules and specifically have obtained information from the above-named subscriber concerning his/her age, net worth, annual income, federal income tax bracket, investment objectives, investment portfolio, and other financial information and have determined that an investment in the Partnership is suitable for such subscriber, that such subscriber is or will be in a financial position to realize the benefits of this investment, and that such subscriber has a fair market net worth sufficient to sustain the risks for this investment. I have also informed the subscriber of all pertinent facts relating to the liquidity and marketability of an investment in the Partnership, of the risks of unlimited liability regarding an investment as an Investor General Partner, and of the passive loss limitations for tax purposes of an investment as a Limited Partner.
- ------------------------------------- --------------------------------------- Name of Registered Representative Name of Broker/Dealer and CRD Number - ------------------------------------- --------------------------------------- Signature of Registered Broker/Dealer CRD Number Representative Registered Representative Broker/Dealer E-mail Address:---------- Office Address: - ------------------------------------- - ------------------------------------- Phone Number:------------------------ Facsimile Number:-------------------- E-mail Address:---------------------- - ------------------------------------- Company Name (if other than Broker/Dealer Name)
NOTICE TO BROKER-DEALER: Send Subscription Documents completed and signed with check MADE PAYABLE TO: "Atlas Public #12-2003 Limited Partnership, Escrow Agent, National City Bank of PA" to: Mr. Justin Atkinson Anthem Securities, Inc. 311 Rouser Road P.O. Box 926 Moon Township, Pennsylvania 15108-0926 (412) 262-1680 (412) 262-7430 (FAX) - ------------------------------------------------------------------------------- TO BE COMPLETED BY THE MANAGING GENERAL PARTNER - -------------------------------------------------------------------------------
ACCEPTED THIS ______ day ATLAS RESOURCES, INC., of _________________ , 2003 MANAGING GENERAL PARTNER By: ------------------------------------------
2 EXHIBIT (II) FORM OF DRILLING AND OPERATING AGREEMENT FOR ATLAS AMERICA PUBLIC #12-2003 LIMITED PARTNERSHIP [ATLAS AMERICA PUBLIC #12-2004(_____) LIMITED PARTNERSHIP] (This Drilling and Operating Agreement Is Written For a Natural Gas Development Well In The Clinton/Medina Geological Formation. The Drilling and Operating Agreement Will Be Appropriately Modified for Different Formations or Areas and Oil Wells.) INDEX
Section Page 1. Assignment of Well Locations; Representations; Designation of Additional Well Locations; Outside Activities Are Not Restricted ........................................................ 1 2. Drilling of Wells; Timing; Depth; Interest of Developer; Right to Substitute Well Locations ............. 2 3. Operator - Responsibilities in General; Covenants; Term ................................................. 3 4. Operator's Charges for Drilling and Completing Wells; Payment; Completion Determination; Dry Hole Determination; Excess Funds and Cost Overruns - Intangible Drilling Costs; Excess Funds and Cost Overruns - Tangible Costs ............................................................................... 4 5. Title Examination of Well Locations; Developer's Acceptance and Liability; Additional Well Locations .... 7 6. Operations Subsequent to Completion of the Wells; Fee Adjustments; Extraordinary Costs; Pipelines; Price Determinations; Plugging and Abandonment ................................................................ 7 7. Billing and Payment Procedure with Respect to Operation of Wells; Disbursements; Separate Account for Sale Proceeds; Records and Reports; Additional Information .............................................. 9 8. Operator's Lien; Right to Collect From Gas Purchaser .................................................... 11 9. Successors and Assigns; Transfers; Appointment of Agent ................................................. 11 10. Operator's Insurance; Subcontractors' Insurance; Operator's Liability ................................... 12 11. Internal Revenue Code Election; Relationship of Parties; Right to Take Production in Kind ............... 13 12. Effect of Force Majeure; Definition of Force Majeure; Limitation ........................................ 14 13. Term .................................................................................................... 14 14. Governing Law; Invalidity ............................................................................... 14 15. Integration; Written Amendment .......................................................................... 15 16. Waiver of Default or Breach ............................................................................. 15 17. Notices ................................................................................................. 15 18. Interpretation .......................................................................................... 15 19. Counterparts ............................................................................................ 15 Signature Page .......................................................................................... 16
Exhibit A Description of Leases and Initial Well Locations Exhibits A-l through A-___ Maps of Initial Well Locations Exhibit B Form of Assignment Exhibit C Form of Addendum
DRILLING AND OPERATING AGREEMENT THIS AGREEMENT made this ______ day of _______________, 200__, by and between ATLAS RESOURCES, INC., a Pennsylvania corporation (hereinafter referred to as "Atlas" or "Operator"), and ATLAS AMERICA PUBLIC #12-2003 Limited Partnership [Atlas America Public #12-2004(_____) Limited Partnership], a Delaware limited partnership, (hereinafter referred to as the "Developer"). WITNESSETH THAT: WHEREAS, the Operator, by virtue of the Oil and Gas Leases (the "Leases") described on Exhibit A attached to and made a part of this Agreement, has certain rights to develop the ____________ (______) initial well locations (the "Initial Well Locations") identified on the maps attached to and made a part of this Agreement as Exhibits A-l through A-______; WHEREAS, the Developer, subject to the terms and conditions of this Agreement, desires to acquire certain of the Operator's rights to develop the Initial Well Locations and to provide for the development on the terms and conditions set forth in this Agreement of additional well locations ("Additional Well Locations") which the parties may from time to time designate; and WHEREAS, the Operator is in the oil and gas exploration and development business, and the Developer desires that Operator, as its independent contractor, perform certain services in connection with its efforts to develop the aforesaid Initial and Additional Well Locations (collectively the "Well Locations") and to operate the wells completed on the Well Locations, on the terms and conditions set forth in this Agreement; NOW THEREFORE, in consideration of the mutual covenants herein contained and subject to the terms and conditions hereinafter set forth, the parties hereto, intending to be legally bound, hereby agree as follows: 1. Assignment of Well Locations; Representations; Designation of Additional Well Locations; Outside Activities Are Not Restricted. (a) Assignment of Well Locations. The Operator shall execute an assignment of an undivided percentage of Working Interest in the Well Location acreage for each well to the Developer as shown on Exhibit A attached hereto, which assignment shall be limited to a depth from the surface to the top of the Queenston formation in Pennsylvania and Ohio when the primary objective is the Clinton/Medina geological formation. In the event that hydrocarbons are encountered in quantities that Operator believes to be in paying quantities and drilling ceases before the Clinton/Medina geological formation is penetrated, then Operator shall execute an assignment limited to a depth from the surface to the deepest depth penetrated at the cessation of drilling operations. The assignment shall be substantially in the form of Exhibit B attached to and made a part of this Agreement. The amount of acreage included in each Initial Well Location and the configuration of the Initial Well Location are indicated on the maps attached as Exhibits A-l through A-______. The amount of acreage included in each Additional Well Location and the configuration of the Additional Well Location shall be indicated on the maps to be attached as exhibits to the applicable addendum to this Agreement as provided in sub- section (c) below. (b) Representations. The Operator represents and warrants to the Developer that: (i) the Operator is the lawful owner of the Lease and rights and interest under the Lease and of the personal property on the Lease or used in connection with the Lease; (ii) the Operator has good right and authority to sell and convey the rights, interest, and property; (iii) the rights, interest, and property are free and clear from all liens and encumbrances; and (iv) all rentals and royalties due and payable under the Lease have been duly paid. 1 These representations and warranties shall also be included in each recorded assignment of the acreage included in each Initial Well Location and Additional Well Location designated pursuant to sub-section (c) below, substantially in the manner set forth in Exhibit B. The Operator agrees to indemnify, protect and hold the Developer and its successors and assigns harmless from and against all costs (including but not limited to reasonable attorneys' fees), liabilities, claims, penalties, losses, suits, actions, causes of action, judgments or decrees resulting from the breach of any of the above representations and warranties. It is understood and agreed that, except as specifically set forth above, the Operator makes no warranty or representation, express or implied, as to its title or the title of the lessors in and to the lands or oil and gas interests covered by said Leases. (c) Designation of Additional Well Locations. If the parties hereto desire to designate Additional Well Locations to be developed in accordance with the terms and conditions of this Agreement, then the parties shall execute an addendum substantially in the form of Exhibit C attached to and made a part of this Agreement (Exhibit "C") specifying: (i) the undivided percentage of Working Interest and the Oil and Gas Leases to be included as Leases under this Agreement; (ii) the amount and configuration of acreage included in each Additional Well Location on maps attached as exhibits to the addendum; and (iii) their agreement that the Additional Well Locations shall be developed in accordance with the terms and conditions of this Agreement. (d) Outside Activities Are Not Restricted. It is understood and agreed that the assignment of rights under the Leases and the oil and gas development activities contemplated by this Agreement relate only to the Initial Well Locations and the Additional Well Locations. Nothing contained in this Agreement shall be interpreted to restrict in any manner the right of each of the parties to conduct without the participation of the other party any additional activities relating to exploration, development, drilling, production, or delivery of oil and gas on lands adjacent to or in the immediate vicinity of the Well Locations or elsewhere. 2. Drilling of Wells; Timing; Depth; Interest of Developer; Right to Substitute Well Locations. (a) Drilling of Wells. Operator, as Developer's independent contractor, agrees to drill, complete (or plug) and operate ____________ (_____) natural gas wells on the ____________ (______) Initial Well Locations in accordance with the terms and conditions of this Agreement. Developer, as a minimum commitment, agrees to participate in and pay the Operator's charges for drilling and completing the wells and any extra costs pursuant to Section 4 in proportion to the share of the Working Interest owned by the Developer in the wells with respect to all initial wells. It is understood and agreed that, subject to sub-section (e) below, Developer does not reserve the right to decline participation in the drilling of any of the initial wells to be drilled under this Agreement. (b) Timing. Operator will use its best efforts to begin drilling the first well within thirty (30) days after the date of this Agreement and will use its best efforts to begin drilling each of the other initial wells for which payment is made pursuant to Section 4(b) of this Agreement, before the close of the 90th day after the close of the calendar year in which this Agreement is entered into by Operator and the Developer. Subject to the foregoing time limits, Operator shall determine the timing of and the order of drilling the Initial Well Locations. (c) Depth. All of the wells to be drilled under this Agreement (c) shall be: (i) drilled and completed (or plugged) in accordance with the generally accepted and customary oil and gas field practices and techniques then prevailing in the geographical area of the Well Locations; and (ii) drilled to a depth sufficient to test thoroughly the objective formation or the deepest assigned depth, whichever is less. 2 (d) Interest of Developer. Except as otherwise provided in this Agreement, all costs, expenses, and liabilities incurred in connection with the drilling and other operations and activities contemplated by this Agreementshall be borne and paid, and all wells, gathering lines of up to approximately 2,500 feet on the Well Location, equipment, materials, and facilities acquired, constructed or installed under this Agreement shall be owned, by the Developer in proportion to the share of the Working Interest owned by the Developer in the wells. Subject to the payment of lessor's royalties and other royalties and overriding royalties, if any, production of oil and gas from the wells to be drilled under this Agreement shall be owned by the Developer in proportion to the share of the Working Interest owned by the Developer in the wells. (e) Right to Substitute Well Locations. Notwithstanding the provisions of sub-section (a) above, if the Operator or Developer determines in good faith, with respect to any Well Location, before operations begin under this Agreement on the Well Location, that it would not be in the best interest of the parties to drill a well on the Well Location, then the party making the determination shall notify the other party of its determination and its basis for its determination and, unless otherwise instructed by Developer, the well shall not be drilled. This determination may be based on: (i) the production or failure of production of any other wells which may have been recently drilled in the immediate area of the Well Location; (ii) newly discovered title defects; or (iii) any other evidence with respect to the Well Location as may be obtained. If the well is not drilled, then Operator shall promptly propose a new well location (including all information for the Well Location as Developer may reasonably request) within Pennsylvania, Ohio, or other areas of the United States to be substituted for the original Well Location. Developer shall then have seven (7) business days to either reject or accept the proposed new well location. If the new well location is rejected, then Operator shall promptly propose another substitute well location pursuant to the provisions of this sub-section. Once the Developer accepts a substitute well location or does not reject it within said seven (7) day period, this Agreement shall terminate as to the original Well Location and the substitute well location shall become subject to the terms and conditions of this Agreement. 3. Operator - Responsibilities in General; Covenants; Term. (a) Operator - Responsibilities in General. Atlas shall be the Operator of the wells and Well Locations subject to this Agreement and, as the Developer's independent contractor, shall, in addition to its other obligations under this Agreement do the following: (i) arrange for drilling and completing the wells and installing the necessary gas gathering line systems and connection facilities; (ii) make the technical decisions required in drilling, testing, completing, and operating the wells; (iii) manage and conduct all field operations in connection with the drilling, testing, completing, equipping, operating, and producing the wells; (iv) maintain all wells, equipment, gathering lines, and facilities in good working order during their useful lives; and (v) perform the necessary administrative and accounting functions. In performing the work contemplated by this Agreement, Operator is an independent contractor with authority to control and direct the performance of the details of the work. (b) Covenants. Operator covenants and agrees that under this Agreement: 3 (i) it shall perform and carry on (or cause to be performed and carried on) its duties and obligations in a good, prudent, diligent, and workmanlike manner using technically sound, acceptable oil and gas field practices then prevailing in the geographical area of the Well Locations; (ii) all drilling and other operations conducted by, for and under the control of Operator shall conform in all respects to federal, state and local laws, statutes, ordinances, regulations, and requirements; (iii) unless otherwise agreed in writing by the Developer, all work performed pursuant to a written estimate shall conform to the technical specifications set forth in the written estimate and all equipment and materials installed or incorporated in the wells and facilities shall be new or used and of good quality; (iv) in the course of conducting operations, it shall comply with all terms and conditions, other than any minimum drilling commitments, of the Leases (and any related assignments, amendments, subleases, modifications and supplements); (v) it shall keep the Well Locations and all wells, equipment and facilities located on the Well Locations free and clear of all labor, materials and other liens or encumbrances arising out of operations; (vi) it shall file all reports and obtain all permits and bonds required to be filed with or obtained from any governmental authority or agency in connection with the drilling or other operations and activities; and (vii) it will provide competent and experienced personnel to supervise drilling, completing (or plugging), and operating the wells and use the services of competent and experienced service companies to provide any third party services necessary or appropriate in order to perform its duties. (c) Term. Atlas shall serve as Operator under this Agreement until the earliest of: (i) the termination of this Agreement pursuant to Section 13; (ii) the termination of Atlas as Operator by the Developer at any time in the Developer's discretion, with or without cause on sixty (60) days' advance written notice to the Operator; or (iii) the resignation of Atlas as Operator under this Agreement which may occur on ninety (90) days' written notice to the Developer at any time after five (5) years from the date of this Agreement, it being expressly understood and agreed that Atlas shall have no right to resign as Operator before the expiration of the five-year period. Any successor Operator shall be selected by the Developer. Nothing contained in this sub-section shall relieve or release Atlas or the Developer from any liability or obligation under this Agreement which accrued or occurred before Atlas' removal or resignation as Operator under this Agreement. On any change in Operator under this provision, the then present Operator shall deliver to the successor Operator possession of all records, equipment, materials and appurtenances used or obtained for use in connection with operations under this Agreement and owned by the Developer. 4. Operator's Charges for Drilling and Completing Wells; Payment; Completion Determination; Dry Hole Determination; Excess Funds and Cost Overruns- Intangible Drilling Costs; Excess Funds and Cost Overruns-Tangible Costs. (a) Operator's Charges for Drilling and Completing Wells. All natural gas wells which are drilled and completed under this Agreement shall be drilled and completed on a Cost plus 15% basis. "Cost," when used with respect to services, shall mean the reasonable, necessary, and actual expenses incurred by Operator on behalf of Developer in providing the services under this Agreement, determined in accordance with generally accepted accounting principles. As used elsewhere, "Cost" shall mean the price paid by Operator in an arm's-length transaction. The estimated price for each of the wells shall be set forth in an Authority for Expenditure ("AFE") which shall be attached to this Agreement as an Exhibit, and shall cover all ordinary costs which may be incurred in 4 drilling and completing each well for production of natural gas. This includes without limitation, site preparation, permits and bonds, roadways, surface damages, power at the site, water, Operator's overhead and profit, rights-of-way, drilling rigs, equipment and materials, logging, cementing, fracturing, casing, meters (other than utility purchase meters), connection facilities, salt water collection tanks, separators, siphon string, rabbit, tubing, an average of 2,500 feet of gathering line per well, geological and engineering services and completing two (2) zones. The estimated price shall not include the cost of: (i) completing more than two (2) zones; (ii) completion procedures, equipment, or any facilities necessary or appropriate for the production and sale of oil and/or natural gas liquids; and (iii) equipment or materials necessary or appropriate to collect, lift, or dispose of liquids for efficient gas production, except that the cost of saltwater collection tanks, separators, siphon string and tubing shall be included in the estimated price. These extra costs, if any, shall be billed to Developer in proportion to the share of the Working Interest owned by the Developer in the wells on a Cost plus 15% basis. (b) Payment. The Developer shall pay to Operator, in proportion to the share of the Working Interest owned by the Developer in the wells, one hundred percent (100%) of the estimated Intangible Drilling Costs and Tangible Costs as those terms are defined below, for drilling and completing all initial wells on execution of this Agreement. Notwithstanding, Atlas' payments for its share of the estimated Tangible Costs as that term is defined below of drilling and completing all initial wells as the Managing General Partner of the Developer shall be paid within five (5) business days of notice from Operator that the costs have been incurred. The Developer's payment shall be nonrefundable in all events in order to enable Operator to do the following: (i) commence site preparation for the initial wells; (ii) obtain suitable subcontractors for drilling and completing the wells at currently prevailing prices; and (iii) insure the availability of equipment and materials. For purposes of this Agreement, "Intangible Drilling Costs" shall mean those expenditures associated with property acquisition and the drilling and completion of oil and gas wells that under present law are generally accepted as fully deductible currently for federal income tax purposes. This includes all expenditures made with respect to any well before the establishment of production in commercial quantities for wages, fuel, repairs, hauling, supplies and other costs and expenses incident to and necessary for the drilling of the well and the preparation of the well for the production of oil or gas, that are currently deductible pursuant to Section 263(c) of the Internal Revenue Code of 1986, as amended, (the "Code"), and Treasury Reg. Section 1.612-4, which are generally termed "intangible drilling and development costs," including the expense of plugging and abandoning any well before a completion attempt. "Tangible Costs" shall mean those costs associated with the drilling and completion of oil and gas wells which are generally accepted as capital expenditures pursuant to the provisions of the Code. This includes all costs of equipment, parts and items of hardware used in drilling and completing a well, and those items necessary to deliver acceptable oil and gas production to purchasers to the extent installed downstream from the wellhead of any well and which are required to be capitalized under the Code and its regulations. With respect to each additional well drilled on the Additional Well Locations, if any, Developer shall pay Operator, in proportion to the share of the Working Interest owned by the Developer in the wells, one hundred percent (100%) of the estimated Intangible Drilling Costs and Tangible Costs for the well on execution of the applicable addendum pursuant to Section l(c) above. Notwithstanding, Atlas' payments for its share of the estimated Tangible Costs of drilling and completing all additional wells as the Managing General Partner of the Developer shall be paid within five (5) business days of notice from Operator that the costs have been incurred. The Developer's payment shall be nonrefundable in all events in order to enable Operator to do the following: 5 (i) commence site preparation; (ii) obtain suitable subcontractors for drilling and completing the wells at currently prevailing prices; and (iii) insure the availability of equipment and materials. Developer shall pay, in proportion to the share of the Working Interest owned by the Developer in the wells, any extra costs incurred for each well pursuant to sub-section (a) above within ten (10) business days of its receipt of Operator's statement for the extra costs. (c) Completion Determination. Operator shall determine whether or not to run the production casing for an attempted completion or to plug and abandon any well drilled under this Agreement. However, a well shall be completed only if Operator has made a good faith determination that there is a reasonable possibility of obtaining commercial quantities of oil and/or gas. (d) Dry Hole Determination. If Operator determines at any time during the drilling or attempted completion of any well under this Agreement, in accordance with the generally accepted and customary oil and gas field practices and techniques then prevailing in the geographic area of the Well Location that the well should not be completed, then it shall promptly and properly plug and abandon the well. (e) Excess Funds and Cost Overruns-Intangible Drilling Costs. Any estimated Intangible Drilling Costs paid by Developer with respect to any well which exceed Operator's price specified in sub-section (a) above for the Intangible Drilling Costs of the well shall be retained by Operator and shall be applied to: (i) the Intangible Drilling Costs for an additional well or wells to be drilled on the Additional Well Locations; or (ii) any cost overruns owed by the Developer to Operator for Intangible Drilling Costs on one or more of the other wells on the Well Locations; in proportion to the share of the Working Interest owned by the Developer in the wells. Conversely, if Operator's price specified in sub-section (a) above for the Intangible Drilling Costs of any well exceeds the estimated Intangible Drilling Costs paid by Developer for the well, then: (i) Developer shall pay the additional price to Operator within five (5) business days after notice from Operator that the additional amount is due and owing; or (ii) Developer and Operator may agree to delete or reduce Developer's Working Interest in one or more wells which have not yet been spudded to provide funds to pay the additional amounts to Operator. If doing so results in any excess prepaid Intangible Drilling Costs, then these funds shall be applied to: (a) the Intangible Drilling Costs for an additional well or wells to be drilled on the Additional Well Locations; or (b) any cost overruns owed by Developer to Operator for Intangible Drilling Costs on one or more of the other wells on the Well Locations; in proportion to the share of the Working Interest owned by the Developer in the wells. The Exhibits to this Agreement with respect to the affected wells shall be amended as appropriate. (f) Excess Funds and Cost Overruns - Tangible Costs. Any estimated Tangible Costs paid by Developer with respect to any well which exceed Operator's price specified in sub-section (a) above for the Tangible Costs of the well shall be retained by Operator and shall be applied to: 6 (i) the Intangible Drilling Costs or Tangible Costs for an additional well or wells to be drilled on the Additional Well Locations; or (ii) any cost overruns owed by Developer to Operator for Intangible Drilling Costs or Tangible Costs on one or more of the other wells on the Well Locations; in proportion to the share of the Working Interest owned by the Developer in the wells. Conversely, if Operator's price specified in sub-section (a) above for the Tangible Costs of any well exceeds the estimated Tangible Costs paid by Developer for the well, then: (i) Developer shall pay the additional price to Operator within ten (10) business days after notice from Operator that the additional price is due and owing; or (ii) Developer and Operator may agree to delete or reduce Developer's Working Interest in one or more wells which have not yet been spudded to provide funds to pay the additional price to Operator. If doing so results in any excess prepaid Tangible Costs, then these funds shall be applied to: (a) the Intangible Drilling Costs or Tangible Costs for an additional well or wells to be drilled on the Additional Well Locations; or (b) any cost overruns owed by Developer to Operator for Intangible Drilling Costs or Tangible Costs on one or more of the other wells on the Well Locations; in proportion to the share of the Working Interest owed by the Developer in the wells. The Exhibits to this Agreement with respect to the affected wells shall be amended as appropriate. 5. Title Examination of Well Locations, Developer's Acceptance and Liability; Additional Well Locations. (a) Title Examination of Well Locations, Developer's Acceptance and Liability. The Developer acknowledges that Operator has furnished Developer with the title opinions identified on Exhibit A, and other documents and information which Developer or its counsel has requested in order to determine the adequacy of the title to the Initial Well Locations and leased premises subject to this Agreement. The Developer accepts the title to the Initial Well Locations and leased premises and acknowledges and agrees that, except for any loss, expense, cost, or liability caused by the breach of any of the warranties and representations made by the Operator in Section l(b), any loss, expense, cost or liability whatsoever caused by or related to any defect or failure of the title shall be the sole responsibility of and shall be borne entirely by the Developer. (b) Additional Well Locations. Before beginning drilling of any well on any Additional Well Location, Operator shall conduct, or cause to be conducted, a title examination of the Additional Well Location, in order to obtain appropriate abstracts, opinions and certificates and other information necessary to determine the adequacy of title to both the applicable Lease and the fee title of the lessor to the premises covered by the Lease. The results of the title examination and such other information as is necessary to determine the adequacy of title for drilling purposes shall be submitted to the Developer for its review and acceptance. No drilling on the Additional Well Locations shall begin until the title has been accepted in writing by the Developer. After any title has been accepted by the Developer, any loss, expense, cost, or liability whatsoever, caused by or related to any defect or failure of the title shall be the sole responsibility of and shall be borne entirely by the Developer, unless such loss, expense, cost, or liability was caused by the breach of any of the warranties and representations made by the Operator in Section l(b). 6. Operations Subsequent to Completion of the Wells; Fee Adjustments; Extraordinary Costs; Pipelines; Price Determinations; Plugging and Abandonment. (a) Operations Subsequent to Completion of the Wells. Beginning with the month in which a well drilled under this Agreement begins to produce, Operator shall be entitled to an operating fee of $275 per month for 7 each well being operated under this Agreement, proportionately reduced to the extent the Developer owns less than 100% of the Working Interest in the wells. This fee shall be in lieu of any direct charges by Operator for its services or the provision by Operator of its equipment for normal superintendence and maintenance of the wells and related pipelines and facilities. If a third-party serves as the actual operator of the well, then this fee shall be $25 above the actual third-party operator's monthly charges. The $25 will be retained by Operator each month for reviewing the costs and expenses charged by the third-party operator and monitoring the third- party operator's accounting and production records for the well on behalf of the Developer. The operating fees shall cover all normal, regularly recurring operating expenses for the production, delivery and sale of natural gas, including without limitation: (i) well tending, routine maintenance and adjustment; (ii) reading meters, recording production, pumping, maintaining appropriate books and records; (iii) preparing reports to the Developer and government agencies; and (iv) collecting and disbursing revenues. The operating fees shall not cover costs and expenses related to the following: (i) the production and sale of oil; (ii) the collection and disposal of salt water or other liquids produced by the wells; (iii) the rebuilding of access roads; and (iv) the purchase of equipment, materials or third party services; which, subject to the provisions of sub-section (c) of this Section 6, shall be paid by the Developer in proportion to the share of the Working Interest owned by the Developer in the wells. Any well which is temporarily abandoned or shut-in continuously for the entire month shall not be considered a producing well for purposes of determining the number of wells in the month subject to the operating fee. (b) Fee Adjustments. The monthly operating fee set forth in sub- section (a) above may in the following manner be adjusted annually as of the first day of January (the "Adjustment Date") each year beginning January l, 2005 with respect to the partnership designated Atlas America Public #12-2003 Limited Partnership, and January 1, 2006 with respect to partnerships designated as Atlas America Public #12-2004(_____) Limited Partnership. Such adjustment, if any, shall not exceed the percentage increase in the average weekly earnings of "Crude Petroleum, Natural Gas, and Natural Gas Liquids" workers, as published by the U.S. Department of Labor, Bureau of Labor Statistics, and shown in Employment and Earnings Publication, Monthly Establishment Data, Hours and Earning Statistical Table C-2, Index Average Weekly Earnings of "Crude Petroleum, Natural Gas, and Natural Gas Liquids" workers, SIC Code #131-2, or any successor index thereto, since January l, 2002, in the case of the first adjustment, and since the previous Adjustment Date, in the case of each subsequent adjustment. (c) Extraordinary Costs. Without the prior written consent of the Developer, pursuant to a written estimate submitted by Operator, Operator shall not undertake any single project or incur any extraordinary cost with respect to any well being produced under this Agreement reasonably estimated to result in an expenditure of more than $5,000, unless the project or extraordinary cost is necessary for the following: (i) to safeguard persons or property; or (ii) to protect the well or related facilities in the event of a sudden emergency. 8 In no event, however, shall the Developer be required to pay for any project or extraordinary cost arising from the negligence or misconduct of Operator, its agents, servants, employees, contractors, licensees, or invitees. All extraordinary costs incurred and the cost of projects undertaken with respect to a well being produced shall be billed at the invoice cost of third-party services performed or materials purchased together with a reasonable charge by Operator for services performed directly by it, in proportion to the share of the Working Interest owned by the Developer in the wells. Operator shall have the right to require the Developer to pay in advance of undertaking any project all or a portion of the estimated costs of the project in proportion to the share of the Working Interest owned by the Developer in the wells. (d) Pipelines. Developer shall have no interest in the pipeline gathering system, which gathering system shall remain the sole property of Operator or its Affiliates and shall be maintained at their sole cost and expense. (e) Price Determinations. Notwithstanding anything herein to the contrary, the Developer shall have full responsibility for and bear all costs in proportion to the share of the Working Interest owned by the Developer in the wells with respect to obtaining price determinations under and otherwise complying with the Natural Gas Policy Act of 1978 and the implementing state regulations. This responsibility shall include, without limitation, preparing, filing, and executing all applications, affidavits, interim collection notices, reports and other documents necessary or appropriate to obtain price certification, to effect sales of natural gas, or otherwise to comply with the Act and the implementing state regulations. Operator agrees to furnish the information and render the assistance as the Developer may reasonably request in order to comply with the Act and the implementing state regulations without charge for services performed by its employees. (f) Plugging and Abandonment. The Developer shall have the right to direct Operator to plug and abandon any well that has been completed under this Agreement as a producer. In addition, Operator shall not plug and abandon any well that has been drilled and completed as a producer before obtaining the written consent of the Developer. However, if the Operator in accordance with the generally accepted and customary oil and gas field practices and techniques then prevailing in the geographic area of the well location, determines that any well should be plugged and abandoned and makes a written request to the Developer for authority to plug and abandon the well and the Developer fails to respond in writing to the request within forty-five (45) days following the date of the request, then the Developer shall be deemed to have consented to the plugging and abandonment of the well. All costs and expenses related to plugging and abandoning the wells which have been drilled and completed as producing wells shall be borne and paid by the Developer in proportion to the share of the Working Interest owned by the Developer in the wells. Also, at any time after one (1) year from the date each well drilled and completed is placed into production, Operator shall have the right to deduct each month from the proceeds of the sale of the production from the well up to $200, in proportion to the share of the Working Interest owned by the Developer in the wells, for the purpose of establishing a fund to cover the estimated costs of plugging and abandoning the well. All these funds shall be deposited in a separate interest bearing escrow account for the account of the Developer, and the total amount so retained and deposited shall not exceed Operator's reasonable estimate of the costs. 7. Billing and Payment Procedure with Respect to Operation of Wells; Disbursements; Separate Account for Sale Proceeds; Records and Reports; Additional Information. (a) Billing and Payment Procedure with Respect to Operation of Wells. Operator shall promptly and timely pay and discharge on behalf of the Developer, in proportion to the share of the Working Interest owned by the Developer in the wells the following: (i) all expenses and liabilities payable and incurred by reason of its operation of the wells in accordance with this Agreement , such as severance taxes, royalties, overriding royalties, operating fees, and pipeline gathering charges; and 9 (ii) any third-party invoices rendered to Operator with respect to costs and expenses incurred in connection with the operation of the wells. Operator, however, shall not be required to pay and discharge any of the above costs and expenses which are being contested in good faith by Operator. Operator shall: (i) deduct the foregoing costs and expenses from the Developer's share of the proceeds of the oil and/or gas sold from the wells; and (ii) keep an accurate record of the Developer's account, showing expenses incurred and charges and credits made and received with respect to each well. If the proceeds are insufficient to pay the costs and expenses, then Operator shall promptly and timely pay and discharge the costs and expenses, in proportion to the share of the Working Interest owned by the Developer in the wells, and prepare and submit an invoice to the Developer each month for the costs and expenses. The invoice shall be accompanied by the form of statement specified in sub-section (b) below, and shall be paid by the Developer within ten (10) business days of its receipt. (b) Disbursements. Operator shall disburse to the Developer, on a monthly basis, the Developer's share of the proceeds received from the sale of oil and/or gas sold from the wells operated under this Agreement, less: (i) the amounts charged to the Developer under sub-section (a); and (ii) the amount, if any, withheld by Operator for future plugging costs pursuant to sub-section (f) of Section 6. Each disbursement made and/or invoice submitted pursuant to sub-section (a) above shall be accompanied by a statement itemizing with respect to each well: (i) the total production of oil and/or gas since the date of the last disbursement or invoice billing period, as the case may be, and the Developer's share of the production; (ii) the total proceeds received from any sale of the production, and the Developer's share of the proceeds; (iii) the costs and expenses deducted from the proceeds and/or being billed to the Developer pursuant to sub-section (a) above; (iv) the amount withheld for future plugging costs; and (v) any other information as Developer may reasonably request, including without limitation copies of all third-party invoices listed on the statement for the period. (c) Separate Account for Sale Proceeds. Operator agrees to deposit all proceeds from the sale of oil and/or gas sold from the wells operated under this Agreement in a separate checking account maintained by Operator. This account shall be used solely for the purpose of collecting and disbursing funds constituting proceeds from the sale of production under this Agreement. (d) Records and Reports. In addition to the statements required under sub-section (b) above, Operator, within seventy-five (75) days after the completion of each well drilled, shall furnish the Developer with a detailed statement itemizing with respect to the well the total costs and charges under Section 4(a) and the Developer's share of the costs and charges, and any information as is necessary to enable the Developer: (i) to allocate any extra costs incurred with respect to the well between Tangible Costs and Intangible Drilling Costs; and (ii) to determine the amount of investment tax credit, if applicable. 10 (e) Additional Information. On request, Operator shall promptly furnish the Developer with any additional information as it may reasonably request, including without limitation geological, technical, and financial information, in the form as may reasonably be requested, pertaining to any phase of the operations and activities governed by this Agreement. The Developer and its authorized employees, agents and consultants, including independent accountants shall, at Developer's sole cost and expense: (i) on at least ten (10) days' written notice have access during normal business hours to all of Operator's records pertaining to operations, including without limitation, the right to audit the books of account of Operator relating to all receipts, costs, charges, expenses and disbursements under this Agreement (including information regarding the separate account required under sub-section (c)); and (ii) have access, at its sole risk, to any wells drilled by Operator under this Agreement at all times to inspect and observe any machinery, equipment and operations. 8. Operator's Lien; Right to Collect From Gas Purchaser. (a) Operator's Lien. To secure the payment of all sums due from Developer to Operator under the provisions of this Agreement the Developer grants Operator a first and preferred lien on and security interest in the following: (i) the Developer's interest in the Leases covered by this Agreement; (ii) the Developer's interest in oil and gas produced under this Agreement and its proceeds from the sale of the oil and gas; and (iii) the Developer's interest in materials and equipment under this Agreement. (b) Right to Collect From Gas Purchaser. If the Developer fails to timely pay any amount owing under this Agreement by it to the Operator, then Operator, without prejudice to other existing remedies, may collect and retain from any purchaser or purchasers of oil or gas the Developer's share of the proceeds from the sale of the oil and gas until the amount owed by the Developer, plus twelve percent (12%) interest on a per annum basis, and any additional costs (including without limitation actual attorneys' fees and costs) resulting from the delinquency, has been paid. Each purchaser of oil or gas shall be entitled to rely on Operator's written statement concerning the amount of any default. 9. Successors and Assigns; Transfers; Appointment of Agent. (a) Successors and Assigns. This Agreement shall be binding on and inure to the benefit of the undersigned parties and their respective successors and permitted assigns. However, without the prior written consent of the Developer, the Operator may not assign, transfer, pledge, mortgage, hypothecate, sell or otherwise dispose of any of its interest in this Agreement, or any of the rights or obligations under this Agreement. Notwithstanding, this consent shall not be required in connection with: (i) the assignment of work to be performed for Operator by subcontractors, it being understood and agreed, however, that any assignment to Operator's subcontractors shall not in any manner relieve or release Operator from any of its obligations and responsibilities under this Agreement; (ii) any lien, assignment, security interest, pledge or mortgage arising under Operator's present or future financing arrangements; or (iii) the liquidation, merger, consolidation, or other corporate reorganization or sale of substantially all of the assets of Operator. Further, in order to maintain uniformity of ownership in the wells, production, equipment, and leasehold interests covered by this Agreement, and notwithstanding any other provisions to the contrary, the Developer shall not, without the prior written consent of Operator, sell, assign, transfer, encumber, mortgage or 11 otherwise dispose of any of its interest in the wells, production, equipment or leasehold interests covered by this Agreement unless the disposition encompasses either: (i) the entire interest of the Developer in all wells, production, equipment and leasehold interests subject to this Agreement; or (ii) an equal undivided interest in all such wells, production, equipment, and leasehold interests. (b) Transfers. Subject to the provisions of sub-section (a) above, any sale, encumbrance, transfer or other disposition made by the Developer of its interests in the wells, production, equipment, and/or leasehold interests covered by this Agreement shall be made: (i) expressly subject to this Agreement; (ii) without prejudice to the rights of the Operator; and (iii) in accordance with and subject to the provisions of the Lease. (c) Appointment of Agent. If at any time the interest of the Developer is divided among or owned by co-owners, Operator may, at its discretion, require the co-owners to appoint a single trustee or agent with full authority to do the following: (i) receive notices, reports and distributions of the proceeds from production; (ii) approve expenditures; (iii) receive billings for and approve and pay all costs, expenses and liabilities incurred under this Agreement; (iv) exercise any rights granted to the co-owners under this Agreement; (v) grant any approvals or authorizations required or contemplated by this Agreement; (vi) sign, execute, certify, acknowledge, file and/or record any agreements, contracts, instruments, reports, or documents whatsoever in connection with this Agreement or the activities contemplated by this Agreement; and (vii) deal generally with, and with power to bind, the co- owners with respect to all activities and operations contemplated by this Agreement. However, all the co-owners shall continue to have the right to enter into and execute all contracts or agreements for their respective shares of the oil and gas produced from the wells drilled under this Agreement in accordance with sub-section (c) of Section 11. 10. Operator's Insurance; Subcontractors' Insurance; Operator's Liability. (a) Operator's Insurance. Operator shall obtain and maintain at its own expense so long as it is Operator under this Agreement all required Workmen's Compensation Insurance and comprehensive general public liability insurance in amounts and coverage not less than $1,000,000 per person per occurrence for personal injury or death and $1,000,000 for property damage per occurrence, which shall include coverage for blow-outs and total liability coverage of not less than $10,000,000. Subject to the above limits, the Operator's general public liability insurance shall be in all respects comparable to that generally maintained in the industry with respect to services of the type to be rendered and activities of the type to be conducted under this Agreement. Operator's general public liability insurance shall, if permitted by Operator's insurance carrier: 12 (i) name the Developer as an additional insured party; and (ii) provide that at least thirty (30) days' prior notice of cancellation and any other adverse material change in the policy shall be given to the Developer. However, the Developer shall reimburse Operator for the additional cost, if any, of including it as an additional insured party under the Operator's insurance. Current copies of all policies or certificates of the Operator's insurance coverage shall be delivered to the Developer on request. It is understood and agreed that Operator's insurance coverage may not adequately protect the interests of the Developer and that the Developer shall carry at its expense the excess or additional general public liability, property damage, and other insurance, if any, as the Developer deems appropriate. (b) Subcontractors' Insurance. Operator shall require all of its subcontractors to carry all required Workmen's Compensation Insurance and to maintain such other insurance, if any, as Operator in its discretion may require. (c) Operator's Liability. Operator's liability to the Developer as Operator under this Agreement shall be limited to, and Operator shall indemnify the Developer and hold it harmless from, claims, penalties, liabilities, obligations, charges, losses, costs, damages, or expenses (including but not limited to reasonable attorneys' fees) relating to, caused by or arising out of: (i) the noncompliance with or violation by Operator, its employees, agents, or subcontractors of any local, state or federal law, statute, regulation, or ordinance; (ii) the negligence or misconduct of Operator, its employees, agents or subcontractors; or (iii) the breach of or failure to comply with any provisions of this Agreement. 11. Internal Revenue Code Election; Relationship of Parties; Right to Take Production in Kind. (a) Internal Revenue Code Election. With respect to this Agreement, each of the parties elects under Section 761(a) of the Internal Revenue Code of 1986, as amended, to be excluded from the provisions of Subchapter K of Chapter 1 of Sub Title A of the Internal Revenue Code of 1986, as amended. If the income tax laws of the state or states in which the property covered by this Agreement is located contain, or may subsequently contain, a similar election, each of the parties agrees that the election shall be exercised. Beginning with the first taxable year of operations under this Agreement, each party agrees that the deemed election provided by Section 1.761-2(b)(2)(ii) of the Regulations under the Internal Revenue Code of 1986, as amended, will apply; and no party will file an application under Section 1.761-2 (b)(3)(i) and (ii) of the Regulations to revoke the election. Each party agrees to execute the documents and make the filings with the appropriate governmental authorities as may be necessary to effect the election. (b) Relationship of Parties. It is not the intention of the parties to create, nor shall this Agreement be construed as creating, a mining or other partnership or association or to render the parties liable as partners or joint venturers for any purpose. Operator shall be deemed to be an independent contractor and shall perform its obligations as set forth in this Agreement or as otherwise directed by the Developer. (c) Right to Take Production in Kind. Subject to the provisions of Section 8 above, the Developer shall have the exclusive right to sell or dispose of its proportionate share of all oil and gas produced from the wells to be drilled under this Agreement, exclusive of production: (i) that may be used in development and producing operations; (ii) unavoidably lost; and 13 (iii) used to fulfill any free gas obligations under the terms of the applicable Lease or Leases. Operator shall not have any right to sell or otherwise dispose of the oil and gas. The Developer shall have the exclusive right to execute all contracts relating to the sale or disposition of its proportionate share of the production from the wells drilled under this Agreement. Developer shall have no interest in any gas supply agreements of Operator, except the right to receive Developer's share of the proceeds received from the sale of any gas or oil from wells developed under this Agreement. The Developer agrees to designate Operator or Operator's designated bank agent as the Developer's collection agent in any contracts. On request, Operator shall assist Developer in arranging the sale or disposition of Developer's oil and gas under this Agreement and shall promptly provide the Developer with all relevant information which comes to Operator's attention regarding opportunities for sale of production. If Developer fails to take in kind or separately dispose of its proportionate share of the oil and gas produced under this Agreement, then Operator shall have the right, subject to the revocation at will by the Developer, but not the obligation, to purchase the oil and gas or sell it to others at any time and from time to time, for the account of the Developer at the best price obtainable in the area for the production. Notwithstanding, Operator shall have no liability to Developer should Operator fail to market the production. Any purchase or sale by Operator shall be subject always to the right of the Developer to exercise at any time its right to take in-kind, or separately dispose of, its share of oil and gas not previously delivered to a purchaser. Any purchase or sale by Operator of any other party's share of oil and gas shall be only for reasonable periods of time as are consistent with the minimum needs of the oil and gas industry under the particular circumstances, but in no event for a period in excess of one (1) year. 12. Effect of Force Majeure; Definition of Force Majeure; Limitation. (a) Effect of Force Majeure. If Operator is rendered unable, wholly or in part, by force majeure (as defined below) to carry out its obligations under this Agreement, the Operator shall give to the Developer prompt written notice of the force majeure with reasonably full particulars concerning it. After the notice is given, the obligations of the Operator, so far as it is affected by the force majeure, shall be suspended during but no longer than, the continuance of the force majeure. Operator shall use all reasonable diligence to remove the force majeure as quickly as possible to the extent the same is within reasonable control. (b) Definition of Force Majeure. The term "force majeure" shall mean an act of God, strike, lockout, or other industrial disturbance, act of the public enemy, war, blockade, public riot, lightning, fire, storm, flood, explosion, governmental restraint, unavailability of equipment or materials, plant shut-downs, curtailments by purchasers and any other causes whether of the kind specifically enumerated above or otherwise, which directly precludes Operator's performance under this Agreement and is not reasonably within the control of the Operator. (c) Limitation. The requirement that any force majeure shall be remedied with all reasonable dispatch shall not require the settlement of strikes, lockouts, or other labor difficulty affecting the Operator, contrary to its wishes. The method of handling these difficulties shall be entirely within the discretion of the Operator. 13. Term. This Agreement shall become effective when executed by Operator and the Developer. Except as provided in sub-section (c) of Section 3, this Agreement shall continue and remain in full force and effect for the productive lives of the wells being operated under this Agreement. 14. Governing Law; Invalidity. (a) Governing Law. This Agreement shall be governed by, construed and interpreted in accordance with the laws of the Commonwealth of Pennsylvania. 14 (b) Invalidity. The invalidity or unenforceability of any particular provision of this Agreement shall not affect the other provisions of this Agreement, and this Agreement shall be construed in all respects as if the invalid or unenforceable provision were omitted. 15. Integration; Written Amendment. (a) Integration. This Agreement, including the Exhibits to this Agreement, constitutes and represents the entire understanding and agreement of the parties with respect to the subject matter of this Agreement and supersedes all prior negotiations, understandings, agreements, and representations relating to the subject matter of this Agreement. (b) Written Amendment. No change, waiver, modification, or amendment of this Agreement shall be binding or of any effect unless in writing duly signed by the party against which the change, waiver, modification, or amendment is sought to be enforced. 16. Waiver of Default or Breach. No waiver by any party to any default of or breach by any other party under this Agreement shall operate as a waiver of any future default or breach, whether of like or different character or nature. 17. Notices. Unless otherwise provided in this Agreement, all notices, statements, requests, or demands which are required or contemplated by this Agreement shall be in writing and shall be hand-delivered or sent by registered or certified mail, postage prepaid, to the following addresses until changed by certified or registered letter so addressed to the other party: (i) If to the Operator, to: Atlas Resources, Inc. 311 Rouser Road Moon Township, Pennsylvania 15108 Attention: President (ii) If to Developer, to: Atlas America Public #12-2003 Limited Partnership [Atlas America Public #12-2004(____) Limited Partnership] c/o Atlas Resources, Inc. 311 Rouser Road Moon Township, Pennsylvania 15108 Notices which are served by registered or certified mail on the parties in the manner provided in this Section shall be deemed sufficiently served or given for all purposes under this Agreement at the time the notice is mailed in any post office or branch post office regularly maintained by the United States Postal Service or any successor. All payments shall be hand-delivered or sent by United States mail, postage prepaid to the addresses set forth above until changed by certified or registered letter so addressed to the other party. 18. Interpretation. The titles of the Sections in this Agreement are for convenience of reference only and shall not control or affect the meaning or construction of any of the terms and provisions of this Agreement. As used in this Agreement, the plural shall include the singular and the singular shall include the plural whenever appropriate. 19. Counterparts. The parties may execute this Agreement in any number of separate counterparts, each of which, when executed and delivered by the parties, shall have the force and effect of an original; but all such counterparts shall be deemed to constitute one and the same instrument. 15 IN WITNESS WHEREOF, the parties hereto have duly executed this Agreement as of the day and year first above written. ATLAS RESOURCES, INC. By: ------------------------------------------------------ ATLAS AMERICA PUBLIC #12-2003 LIMITED PARTNERSHIP [ATLAS AMERICA PUBLIC #12-2004(____) LIMITED PARTNERSHIP] By its Managing General Partner: ATLAS RESOURCES, INC. By: ------------------------------------------------------ 16 DESCRIPTION OF LEASES AND INITIAL WELL LOCATIONS [To be completed as information becomes available] 1. WELL LOCATION (a) Oil and Gas Lease from ________________________________ dated _____________________ and recorded in Deed Book Volume __________, Page __________ in the Recorder's Office of County, ____________, covering approximately _________ acres in ____________________________ Township, ___________________ County, __________________________. (b) The portion of the leasehold estate constituting the ____________________________________________ No. __________ Well Location is described on the map attached hereto as Exhibit A-l. (c) Title Opinion of ______________________________, _______________________________________________, _______________________________________________, ________________________________________, dated ___________________, 200___. (d) The Developer's interest in the leasehold estate constituting this Well Location is an undivided % Working Interest to those oil and gas rights from the surface to the bottom of the __________________ Formation, subject to the landowner's royalty interest and overriding royalty interests. Exhibit A Well Name, Twp. County, State ASSIGNMENT OF OIL AND GAS LEASE STATE OF _______________________________ COUNTY OF _____________________________ KNOW ALL MEN BY THESE PRESENTS: THAT the undersigned _______________________________ (hereinafter called "Assignor"), for and in consideration of One Dollar and other valuable consideration ($1.00 ovc), the receipt whereof is hereby acknowledged, does hereby sell, assign, transfer and set over unto _______________________________ _______________________________(hereinafter called "Assignee"), an undivided _____________________________ in, and to, the oil and gas lease described as follows: together with the rights incident thereto and the personal property thereto, appurtenant thereto, or used, or obtained, in connection therewith. And for the same consideration, the assignor covenants with the said assignee his or its heirs, successors, or assigns that assignor is the lawful owner of said lease and rights and interest thereunder and of the personal property thereon or used in connection therewith; that the undersigned has good right and authority to sell and convey the same, and that said rights, interest and property are free and clear from all liens and encumbrances, and that all rentals and royalties due and payable thereunder have been duly paid. In Witness Whereof, the undersigned owner ______ and assignor ______ ha___ signed and sealed this instrument the ______ day of _______________, 200___.
Signed and acknowledged in the ------------------------------------------ presence of - ---------------------------------- ------------------------------------------ - ---------------------------------- ------------------------------------------
Exhibit B (Page 1) ACKNOWLEDGMENT BY INDIVIDUAL STATE OF _________________________ BEFORE ME, a Notary Public, in and for said COUNTY OF ______________________ County and State, on this day personally appeared _ who acknowledged to me that ____ he ____ did sign the foregoing instrument and that the same is _____________ free act and deed. In testimony whereof, I have hereunto set my hand and official seal, at _____________________________, this ______ day of _______________, A.D., 200___. -------------------------------------- Notary Public CORPORATION ACKNOWLEDGMENT STATE OF _________________________ BEFORE ME, a Notary Public, in and for said COUNTY OF _______________________ County and State, on this day personally appeared _ known to me to be the person and officer whose name is subscribed to the foregoing instrument and acknowledged that the same was the act of the said ______________________________________________, a corporation, and that he executed the same as the act of such corporation for the purposes and consideration therein expressed, and in the capacity therein stated. In testimony whereof, I have hereunto set my hand and official seal, at _____________________________, this ______ day of _______________, A.D., 200___. -------------------------------------- Notary Public This instrument prepared by: Atlas Resources, Inc. 311 Rouser Road P.O. Box 611 Moon Township, PA 15108 Exhibit B (Page 2) ADDENDUM NO. __________ TO DRILLING AND OPERATING AGREEMENT DATED ___________________ , 200__ THIS ADDENDUM NO. __________ made and entered into this ______ day of ________________, 200__, by and between ATLAS RESOURCES, INC., a Pennsylvania corporation (hereinafter referred to as "Operator"), and ATLAS AMERICA PUBLIC #12-2003 LIMITED PARTNERSHIP [ATLAS AMERICA PUBLIC #12-2004(____) LIMITED PARTNERSHIP], a Delaware limited partnership, (hereinafter referred to as the Developer). WITNESSETH THAT: WHEREAS, Operator and the Developer have entered into a Drilling and Operating Agreement dated ___________________, 200__, (the "Agreement"), which relates to the drilling and operating of ________________ (______)wells on the ________________ (______) Initial Well Locations identified on the maps attached as Exhibits A-l through A-______ to the Agreement, and provides for the development on the terms and conditions set forth in the Agreement of Additional Well Locations as the parties may from time to time designate; and WHEREAS, pursuant to Section l(c) of the Agreement, Operator and Developer presently desire to designate ________________ Additional Well Locations described below to be developed in accordance with the terms and conditions of the Agreement. NOW, THEREFORE, in consideration of the mutual covenants contained in this Addendum and intending to be legally bound, the parties agree as follows: 1. Pursuant to Section l(c) of the Agreement, the Developer hereby authorizes Operator to drill, complete (or plug) and operate, on the terms and conditions set forth in the Agreement and this Addendum No.__________, ________________ additional wells on the ________________ Additional Well Locations described on Exhibit A to this Addendum and on the maps attached to this Addendum as Exhibits A-______ through A-______. 2. Operator, as Developer's independent contractor, agrees to drill, complete (or plug) and operate the additional wells on the Additional Well Locations in accordance with the terms and conditions of the Agreement and further agrees to use its best efforts to begin drilling the first additional well within thirty (30) days after the date of this Addendum and to begin drilling all the additional wells on or before March 30, 2004. [March 31, 2005] 3. Developer acknowledges that: (a) Operator has furnished Developer with the title opinions identified on Exhibit A to this Addendum; and (b) such other documents and information which Developer or its counsel has requested in order to determine the adequacy of the title to the above Additional Well Locations. The Developer accepts the title to the Additional Well Locations and leased premises in accordance with the provisions of Section 5 of the Agreement. 4. The drilling and operation of the additional wells on the Additional Well Locations shall be in accordance with and subject to the terms and conditions set forth in the Agreement as supplemented by this Addendum No. __________ and except as previously supplemented, all terms and conditions of the Agreement shall remain in full force and effect as originally written. 5. This Addendum No. __________ shall be legally binding on, and shall inure to the benefit of, the parties and their respective successors and permitted assigns. Exhibit C (Page 1) WITNESS the due execution of this Addendum on the day and year first above written. ATLAS RESOURCES, INC. By _________________________________________ ATLAS AMERICA PUBLIC #12-2003 LIMITED PARTNERSHIP [ATLAS AMERICA PUBLIC #12-2004(____) LIMITED PARTNERSHIP] By its Managing General Partner: ATLAS RESOURCES, INC. By _________________________________________ Exhibit C (Page 2) EXHIBIT (B) SPECIAL SUITABILITY REQUIREMENTS AND DISCLOSURES TO INVESTORS SPECIAL SUITABILITY REQUIREMENTS AND DISCLOSURES TO INVESTORS If you are a resident of one of the following states, then you must meet that state's qualification and suitability standards as follows: Special Suitability for Subscribers to Limited Partner Units In California, Michigan, North Carolina, New Hampshire, Ohio, and Pennsylvania. I. If you are a resident of California and you purchase limited partners units, then you must: o have a net worth of not less than $250,000, exclusive of home, home furnishings and automobiles, and expect to have gross income in the current year of $65,000 or more; or o have a net worth of not less than $500,000, exclusive of home, home furnishings and automobiles; or o have a net worth of not less than $1 million; or o expect to have gross income in the current tax year of not less than $200,000. II. If you are a resident of: o Michigan; or o North Carolina; and you purchase limited partner units, then you must: o have a net worth of not less than $225,000, exclusive of home, home furnishings and automobiles; or o have a net worth of not less than $60,000, exclusive of home, home furnishings and automobiles, and estimated current year taxable income as defined in Section 63 of the Internal Revenue Code of $60,000 or more without regard to an investment in the partnership. III.In addition, if you are a resident of: o Michigan; o Ohio; or o Pennsylvania; then you must not make an investment in the partnership in excess of 10% of your net worth, exclusive of home, home furnishings and automobiles. IV. If you are a resident of New Hampshire and you purchase limited partner units, then you must have: o a net worth, exclusive of home, home furnishings, and automobiles of $250,000, or o a net worth, exclusive of home, home furnishings, and automobiles of $125,000, and $50,000 of taxable income. Special Suitability for Subscribers to Investor General Partner Units. I. If you are a resident of California and you purchase investor general partner units, then you must: o have a net worth of not less than $250,000, exclusive of home, home furnishings and automobiles, and expect 1 to have annual gross income in the current year of $120,000 or more; or o have a net worth of not less than $500,000, exclusive of home, home furnishings and automobiles; or o have a net worth of not less than $1 million; or o expect to have gross income in the current year of not less than $200,000. II. If you are a resident of:
o Alabama; o North Carolina; o Tennessee; o Maine; o Ohio; o Texas; or o Massachusetts; o Oklahoma; o Washington. o Minnesota; o Pennsylvania;
and you purchase investor general partner units, then you must: o have an individual or joint net worth with your spouse of $225,000 or more, without regard to the investment in the partnership, exclusive of home, home furnishings and automobiles, and a combined gross income of $100,000 or more for the current year and for the two previous years; or o have an individual or joint net worth with your spouse in excess of $1 million, inclusive of home, home furnishings and automobiles; or o have an individual or joint net worth with your spouse in excess of $500,000, exclusive of home, home furnishings and automobiles; or o have a combined "gross income" as defined in Section 61 of the Internal Revenue Code of 1986, as amended, in excess of $200,000 in the current year and the two previous years. III.If you are a resident of:
o Arizona; o Michigan; o Oregon; o Indiana; o Mississippi; o South Dakota; or o Iowa; o Missouri; o Vermont; o Kansas; o New Mexico; o Kentucky;
and you purchase investor general partner units, then you must: o have an individual or joint net worth with your spouse of $225,000 or more, without regard to the investment in the partnership, exclusive of home, home furnishings and automobiles, and a combined "taxable income" of $60,000 or more for the previous year and expect to have a combined "taxable income" of $60,000 or more for the current year and for the succeeding year; or o have an individual or joint net worth with your spouse in excess of $1 million, inclusive of home, home furnishings and automobiles; or o have an individual or joint net worth with your spouse in excess of $500,000, exclusive of home, home furnishings and automobiles; or o have a combined "gross income" as defined in Section 61 of the Internal Revenue Code of 1986, as amended, in excess of $200,000 in the current year and the two previous years. 2 IV. If you are a resident of New Hampshire and you purchase investor general partner units, then you must: o have a net worth, exclusive of home, home furnishings, and automobiles of $250,000, or o have a net worth, exclusive of home, home furnishings, and automobiles of $125,000, and $50,000 of taxable income. V. In addition, if you are a resident of:
o Iowa; o Ohio; or o Michigan; o Pennsylvania;
then you must not make an investment in the partnership in excess of 10% of your net worth, exclusive of home, furnishings and automobiles. Special Representations For Subscribers of California, Missouri, North Carolina and Pennsylvania. I. If a resident of Missouri, I am aware that: THESE SECURITIES ARE NOT ELIGIBLE FOR ANY TRANSACTIONAL EXEMPTION UNDER THE MISSOURI UNIFORM SECURITIES ACT (SECTION 409.402(b), R.S.MO.(1978). UNLESS THESE SECURITIES ARE AGAIN REGISTERED UNDER THE ACT, THEY MAY NOT BE REOFFERED FOR SALE OR RESOLD IN THE STATE OF MISSOURI (SECTION 409.301, R.S.MO.(1978)). II. If a resident of California, I am aware that: IT IS UNLAWFUL TO CONSUMMATE A SALE OR TRANSFER OF THIS SECURITY, OR ANY INTEREST THEREIN, OR TO RECEIVE ANY CONSIDERATION THEREFOR, WITHOUT THE PRIOR WRITTEN CONSENT OF THE COMMISSIONER OF CORPORATIONS OF THE STATE OF CALIFORNIA, EXCEPT AS PERMITTED IN THE COMMISSIONER'S RULES. As a condition of qualification of the units for sale in the State of California, the following rule is hereby delivered to each California purchaser. California Administrative Code, Title 10, Ch. 3, Rule 260.141.11. Restriction on transfer. (a) The issuer of any security upon which a restriction on transfer has been imposed pursuant to Sections 260.102.6, 260.141.10 and 260.534 shall cause a copy of this section to be delivered to each issuee or transferee of such security at the time the certificate evidencing the security is delivered to the issuee or transferee. (b) It is unlawful for the holder of any such security to consummate a sale or transfer of such security, or any interest therein, without the prior written consent of the Commissioner (until this condition is removed pursuant to Section 260.141.12 of these rules), except: (i) to the issuer; (ii) pursuant to the order or process of any court; (iii) to any person described in Subdivision (i) of Section 25102 of the Code or Section 260.105.14 of these rules; (iv) to the transferor's ancestors, descendants or spouse, or any custodian or trustee for the account of the transferor's ancestors, descendants or spouse, or to a transferee by a trustee or custodian for the account of the transferee or the transferee's ancestors, descendants or spouse; 3 (v) to holders of securities of the same class of the same issuer; (vi) by way of gift or donation inter vivos or on death; (vii) by or through a broker-dealer licensed under the Code (either acting as such or as a finder) to a resident of a foreign state, territory or country who is neither domiciled in this state to the knowledge of the broker- dealer, nor actually present in this state if the sale of such securities is not in violation of any securities law of the foreign state, territory or country concerned; (viii) to a broker-dealer licensed under the Code in a principal transaction, or as an underwriter or member of an underwriting syndicate or selling group; (ix) if the interest sold or transferred is a pledge or other lien given by the purchaser to the seller upon a sale of the security for which the Commissioner's written consent is obtained or under this rule not required; (x) by way of a sale qualified under Sections 25111, 25112, 25113 or 25121 of the Code, of the securities to be transferred, provided that no order under Section 25140 or Subdivision (a) of Section 25143 is in effect with respect to such qualification; (xi) by a corporation or wholly-owned subsidiary of such corporation, or by a wholly-owned subsidiary of a corporation to such corporation; (xii) by way of an exchange qualified under Sections 25111, 25112 or 25113 of the Code, provided that no order under Section 25140 or Subdivision (a) of Section 25143 is in effect with respect to such qualification; (xiii) between residents of foreign states, territories or countries who are neither domiciled nor actually present in this state; (xiv) to the State Controller pursuant to the Unclaimed Property Law or to the administrator of the unclaimed property law of another state; (xv) by the State Controller pursuant to the Unclaimed Property Law or by the administrator of the unclaimed property law of another state if, in either such case, such person (i) discloses to potential purchasers at the sale that transfer of the securities is restricted under this rule, (ii) delivers to each purchaser a copy of this rule, and (iii) advises the Commissioner of the name of each purchaser; (xvi) by a trustee to a successor trustee when such transfer does not involve a change in the beneficial ownership of the securities; (xvii) by way of an offer and sale of outstanding securities in an issuer transaction that is subject to the qualification requirement of Section 25110 of the Code but exempt from that qualification requirement by subdivision (f) of Section 25102; provided that any such transfer is on the condition that any certificate evidencing the security issued to such transferee shall contain the legend required by this section. (c) The certificates representing all such securities subject to such a restriction on transfer, whether upon initial issuance or upon any transfer thereof, shall bear on their face a legend, prominently stamped or printed thereon in capital letters of not less than 10-point size, reading as follows: "IT IS UNLAWFUL TO CONSUMMATE A SALE OR TRANSFER OF THIS SECURITY, OR ANY INTEREST THEREIN, OR TO RECEIVE ANY CONSIDERATION THEREFOR, WITHOUT THE PRIOR WRITTEN CONSENT OF THE COMMISSIONER OF CORPORATIONS OF THE STATE OF CALIFORNIA, EXCEPT AS PERMITTED IN THE COMMISSIONER'S RULES." III.If a resident of North Carolina, I am aware that: IN MAKING AN INVESTMENT DECISION INVESTORS MUST RELY ON THEIR OWN EXAMINATION OF THE PERSON OR ENTITY CREATING THE SECURITIES AND THE TERMS OF THE OFFERING, INCLUDING THE MERITS AND RISKS INVOLVED. THESE SECURITIES HAVE NOT BEEN RECOMMENDED BY ANY FEDERAL OR STATE SECURITIES 4 COMMISSION OR REGULATORY AUTHORITY. FURTHERMORE, THE FOREGOING AUTHORITIES HAVE NOT CONFIRMED THE ACCURACY OR DETERMINED THE ADEQUACY OF THIS DOCUMENT. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE. IV. PENNSYLVANIA INVESTORS: Because the minimum closing amount is less than 10% of the maximum closing amount allowed to a partnership in this offering, you are cautioned to carefully evaluate the partnership's ability to fully accomplish its stated objectives and inquire as to the current dollar volume of partnership subscriptions. 5 TABLE OF CONTENTS
Page Summary of the Offering ....................................... 1 Risk Factors .................................................. 8 Additional Information ........................................ 16 Forward Looking Statements and Associated Risks ............... 16 Investment Objectives ......................................... 17 Actions to be Taken by Managing General Partner to Reduce Risks of Additional Payments by Investor General Partners.... 18 Capitalization and Source of Funds and Use of Proceeds ........ 20 Compensation .................................................. 24 Terms of the Offering ......................................... 31 Prior Activities .............................................. 37 Management .................................................... 44 Management's Discussion and Analysis of Financial Condition, Results of Operations, Liquidity and Capital Resources....... 50 Proposed Activities ........................................... 52 Competition, Markets and Regulation ........................... 66 Participation in Costs and Revenues ........................... 70 Conflicts of Interest ......................................... 76 Fiduciary Responsibility of the Managing General Partner ............................................. 87 Material Federal Income Tax Consequences ...................... 88 Summary of Partnership Agreement .............................. 105 Summary of Drilling and Operating Agreement ................... 107 Reports to Investors .......................................... 108 Presentment Feature ........................................... 109 Transferability of Units ...................................... 111 Plan of Distribution .......................................... 112 Sales Material ................................................ 115 Legal Opinions ................................................ 116 Experts ....................................................... 116 Litigation .................................................... 116 Financial Information Concerning the Managing General Partner and Atlas America Public #12-2003 Limited Partnership........ 116 EXHIBIT (A) - Form of Partnership Agreement of Atlas America Public #12-2003 Limited Partnership [Atlas America Public #12-2004(_____)Limited Partnership] EXHIBIT (I-A) - Form of Managing General Partner Signature Page EXHIBIT (I-B) - Form of Subscription Agreement EXHIBIT (II) - Form of Drilling and Operating Agreement for Atlas America Public #12-2003 Limited Partnership [Atlas America Public #12-2004(______) Limited Partnership] EXHIBIT (B) - Special Suitability Requirements and Disclosures to Investors
No one has been authorized to give any information or make any representations other than those contained in this prospectus in connection with this offering. If given or made, you should not rely on such information or representations as having been authorized by the managing general partner. The delivery of this prospectus does not imply that its information is correct as of any time after its date. This prospectus is not an offer to sell these securities in any state to any person where the offer and sale is not permitted. ATLAS AMERICA PUBLIC #12-2003 PROGRAM ---------- PROSPECTUS ---------- Until December 31, 2004, all dealers that effect transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers' obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions. PART II INFORMATION NOT REQUIRED IN PROSPECTUS Item 13. Other Expenses of Issuance and Distribution. The expenses to be incurred in connection with the issuance and distribution of the securities to be registered, other than underwriting discounts, commissions and expense allowances, are estimated to be as follows:
Accounting Fees and Expenses ....................................... $ 75,000* ----------- Legal Fees (including Blue Sky) and Expenses ....................... 100,000* Printing ........................................................... 300,000* ----------- SEC Registration Fee ............................................... 6,900 Blue Sky Filing Fees (excluding legal fees) ........................ 160,000* NASD Filing Fee .................................................... 8,000 Miscellaneous ...................................................... 2,161,000* ----------- Total ....................................................... $2,810,900* ===========
- --------------- * Estimated Item 14. Indemnification of Directors and Officers. Section 17-108 of the Delaware Corporation Law provides for indemnification of officers, directors, employees and agents by a corporation subject to certain limitations. Under Section 4.05 of the Amended and Restated Certificate and Agreement of Limited Partnership, the Participants, within the limits of their Capital Contributions, and the Partnership, generally agree to indemnify and exonerate the Managing General Partner, the Operator and their Affiliates from claims of liability to any third party arising out of operations of the Partnership provided that: o they determined in good faith that the course of conduct which caused the loss or liability was in the best interest of the Partnership; o they were acting on behalf of or performing services for the Partnership; and o the course of conduct was not the result of their negligence or misconduct. Paragraph 11 of the Dealer-Manager Agreement provides for the indemnification of the Managing General Partner, the Partnership and control persons under specified conditions by the Dealer-Manager and/or Selling Agent. Item 15. Recent Sales of Unregistered Securities. None by the Registrant. Atlas Resources, Inc. ("Atlas"), an Affiliate of the Registrant, has made sales of unregistered and registered securities within the last three years. See the section of the Prospectus captioned "Prior Activities" regarding the sale of limited and general partner interests. In the opinion of Atlas, the foregoing unregistered securities in each case have been and/or are being offered and sold in compliance with exemptions from registration provided by the Securities Act of 1933, as amended, including the exemptions provided by Section 4(2) of that Act and certain rules and regulations promulgated thereunder. The securities in each case have been and/or are being offered and sold to a limited number of persons who had the sophistication to understand the merits and risks of the investment and who had the financial ability to bear such risks. The units of limited and general partner interests were sold to persons who were Accredited Investors, as that term is defined in Regulation D (17 CFR 230.501(a)), or who had, at the time of purchase, a net worth of at least $225,000 (exclusive of home, furnishings and automobiles) or a net worth (exclusive of home, furnishings and automobiles) of at least $125,000 and gross income of at least $75,000, or otherwise satisfied Atlas that the investment was suitable. 1 Item 16. Exhibits and Financial Statement Schedules. (a) Exhibits 1(a) Proposed form of Dealer-Manager Agreement with Anthem Securities, Inc.** 1(b) Proposed form of Dealer-Manager Agreement with Bryan Funding, Inc.** 1(c) Proposed form of Selected Investment Advisor Agreement** 3(a) Articles of Incorporation of Atlas Resources, Inc.* 3(b) Bylaws of Atlas Resources, Inc.* 4(a) Certificate of Limited Partnership for Atlas America Public #12-2003 Limited Partnership** 4(b) Form of Limited Partnership Agreement for Atlas America Public #12-2003 Limited Partnership [Atlas America Public #12-2004(___) Limited Partnership] (See Exhibit (A) to Prospectus) 5 Opinion of Kunzman & Bollinger, Inc. as to the legality of the Units registered hereby** 8 Opinion of Kunzman & Bollinger, Inc. as to tax matters 10(a) Escrow Agreement for Atlas America Public #12-2003 Limited Partnership** 10(b) Escrow Agreement for Atlas America Public #12-2004(A) Limited Partnership** 10(c) Escrow Agreement for Atlas America Public #12-2004(B) Limited Partnership** 10(d) Proposed Form of Drilling and Operating Agreement (See Exhibit (II) to the Form of Limited Partnership Agreement, Exhibit (A) to Prospectus) 10(e) Gas Purchase Agreement dated March 31, 1999 between Northeast Ohio Gas Marketing, Inc. and Atlas Energy Group, Inc., Atlas Resources, Inc., and Resource Energy, Inc. 10(f) Guaranty dated August 12, 2003 between First Energy Corp. and Atlas Resources, Inc. to Gas Purchase Agreement dated March 31, 1999 between Northeast Ohio Gas Marketing, Inc., and Atlas Energy Group, Inc., Atlas Resources, Inc., and Resource Energy, Inc. 23(a) Consent of Independent Certified Public Accountants 23(b) Consent of United Energy Development Consultants, Inc.* 23(c) Consent of Kunzman & Bollinger, Inc. (See Exhibits 5** and 8) 23(d) Consent of Wright & Company, Inc.* 24 Power of Attorney* ----------- * Previously submitted in the Registration Statement filed June 4, 2003. ** Previously submitted in the Pre-Effective Amendment No. 1 filed July 28, 2003. (b) Financial Statement Schedules All financial statement schedules are omitted because the information is not required, is not material or is otherwise included in the financial statements or related notes thereto. Item 17. Undertakings. (a) The undersigned Registrant hereby undertakes: 2 (1) To file, during any period in which offers or sales are being made, a post-effective amendment to this Registration Statement: (i) To include any Prospectus required by Section 10(a)(3) of the Securities Act of 1933. (ii) To reflect in the Prospectus any facts or events arising after the effective date of the Registration Statement (or of the most recent Post-Effective Amendment thereof) which, individually or in the aggregate, represent a fundamental change in the information set forth in the Registration Statement. Notwithstanding the foregoing, any increase or decrease in volume of securities offered (if the total dollar value of the securities offered would not exceed that which was registered) and any deviation from the low or high end of the estimated maximum offering range may be reflected in the form of prospectus filed with the Commission pursuant to Rule 424(b) if, in the aggregate, the changes in volume and price represent no more than a 20% change in the maximum aggregate offering price set forth in the "Calculation of Registration Fee" table in the effective registration statement. (iii) To include any material information with respect to the plan of distribution not previously disclosed in the Registration Statement or any material change to such information in the Registration Statement. Provided, however, that paragraphs (1)(i) and (1)(ii) do not apply if the registration statement is on Form S-3 or Form S-8 and the information required to be included in a post-effective amendment by those paragraphs is contained in periodic reports filed by the registrant pursuant to section 13 or section 15(d) of the Securities Exchange Act of 1934 that are incorporated by reference in the registration statement. (2) That, for the purpose of determining any liability under the Securities Act of 1933, each such post-effective amendment shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof. (3) To remove from registration by means of a post-effective amendment any of the securities being registered which remain unsold at the termination of the offering. The undersigned Registrant hereby undertakes to provide at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser. Because acceleration is requested of the effective date of the Registration Statement pursuant to Rule 461 under the Securities Act, and: (1) provisions or arrangements exist whereby the Registrant may indemnify a director, officer or controlling person of the Registrant against liabilities arising under the Securities Act, or (2) the underwriting agreement contains a provision whereby the Registrant indemnifies the underwriter or controlling persons of the underwriter against such liabilities and a director, officer or controlling person of the Registrant is such an underwriter or controlling person thereof or a member of any firm which is such an underwriter, and (3) the benefits of such indemnification are not waived by such persons, the Registrant makes the following undertaking: Insofar as indemnification for liabilities arising under the Securities Act of 1933 (the "Act") may be permitted to directors, officers and controlling persons of the Registrant pursuant to the foregoing provisions, or otherwise, the Registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the Registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the Registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue. The undersigned Registrant hereby undertakes that: o For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this Registration Statement in reliance upon Rule 430A and contained in a form of prospectus filed by the Registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this Registration Statement as of the time it was declared effective. o For purposes of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof. 3 SIGNATURES Pursuant to the requirements of the Securities Act of 1933, as amended, the Registrant has duly caused this Pre-Effective Amendment No.2 to the Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in Moon Township, Pennsylvania on September 5, 2003.
ATLAS AMERICA PUBLIC #12-2003 PROGRAM (Registrant) By: Atlas Resources, Inc., Managing General Partner By: /s/ Jack L. Hollander --------------------------------- Jack L. Hollander, Senior Vice President - Direct Participation Programs Jack L. Hollander, pursuant to the Registration Statement, has been granted Power of Attorney and is signing on behalf of the names shown below, in the capacities indicated.
In accordance with the requirements of the Securities Act of 1933, this Pre-Effective Amendment No.2 to the Registration Statement has been signed by the following persons in the capacities and on the dates indicated.
Signature Title Date ---------------------- ---------------------------------------------------------------------------------------- ------------- Freddie M. Kotek President, Chief Executive Officer and Chairman of the Board of Directors 09/05/2003 Frank P. Carolas Executive Vice President - Land and Geology and a Director 09/05/2003 Jeffrey C. Simmons Executive Vice President - Operations and a Director 09/05/2003 Nancy J. McGurk Senior Vice President, Chief Financial Officer and Chief Accounting Officer 09/05/2003
As filed with the Securities and Exchange Commission on September 5, 2003 Registration Number 333-105811 SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 ------------------------------------- EXHIBITS TO PRE-EFFECTIVE AMENDMENT NO. 2 TO FORM S-1 REGISTRATION STATEMENT Under THE SECURITIES ACT OF 1933 ------------------------------------- ATLAS AMERICA PUBLIC #12-2003 PROGRAM (Exact name of Registrant as Specified in its Charter) ------------------------------------- Jack L. Hollander, Senior Vice President - Direct Participation Programs Atlas Resources, Inc. 311 Rouser Road, Moon Township, Pennsylvania 15108 (412) 262-2830 (Name, Address and Telephone Number of Agent for Service) ------------------------------------- Copies to: Wallace W. Kunzman, Jr., Esq. Jack L. Hollander Kunzman & Bollinger, Inc. Atlas Resources, Inc. 5100 N. Brookline, Suite 600 311 Rouser Road Oklahoma City, Oklahoma 73112 Moon Township, Pennsylvania 15108 ================================================================================ EXHIBIT INDEX Exhibit No. Description ----------- ----------- 1(a) Proposed form of Dealer-Manager Agreement with Anthem Securities, Inc.** 1(b) Proposed form of Dealer-Manager Agreement with Bryan Funding, Inc.** 1(c) Proposed form of Selected Investment Advisor Agreement** 3(a) Articles of Incorporation of Atlas Resources, Inc.* 3(b) Bylaws of Atlas Resources, Inc.* 4(a) Certificate of Limited Partnership for Atlas America Public #12-2003 Limited Partnership** 4(b) Form of Limited Partnership Agreement for Atlas America Public #12-2003 Limited Partnership [Atlas America Public #12-2004(___) Limited Partnership] (See Exhibit (A) to Prospectus) 5 Opinion of Kunzman & Bollinger, Inc. as to the legality of the Units registered hereby** 8 Opinion of Kunzman & Bollinger, Inc. as to tax matters 10(a) Escrow Agreement for Atlas America Public #12-2003 Limited Partnership** 10(b) Escrow Agreement for Atlas America Public #12-2004(A) Limited Partnership** 10(c) Escrow Agreement for Atlas America Public #12-2004(B) Limited Partnership** 10(d) Proposed form of Drilling and Operating Agreement (See Exhibit (II) to the Form of Limited Partnership Agreement, Exhibit (A) to Prospectus) 10(e) Gas Purchase Agreement dated March 31, 1999 between Northeast Ohio Gas Marketing, Inc. and Atlas Energy Group, Inc., Atlas Resources, Inc., and Resource Energy, Inc. 10(f) Guaranty dated August 12, 2003 between First Energy Corp. and Atlas Resources, Inc. to Gas Purchase Agreement dated March 31, 1999 between Northeast Ohio Gas Marketing, Inc., and Atlas Energy Group, Inc., Atlas Resources, Inc., and Resource Energy, Inc. 23(a) Consent of Independent Certified Public Accountants 23(b) Consent of United Energy Development Consultants, Inc.* 23(c) Consent of Kunzman & Bollinger, Inc. (See Exhibits 5** and 8) 23(d) Consent of Wright & Company, Inc.* 24 Power of Attorney* -------------- * Previously submitted in the Registration Statement filed June 4, 2003. ** Previously Submitted in the Pre-Effective Amendment No. 1 filed July 28, 2003. EX-8 3 ex8.txt EXHIBIT 8 Exhibit 8 OPINION OF KUNZMAN & BOLLINGER, INC. AS TO TAX MATTERS KUNZMAN & BOLLINGER, INC. ATTORNEYS-AT-LAW 5100 N. BROOKLINE, SUITE 600 OKLAHOMA CITY, OKLAHOMA 73112 Telephone (405) 942-3501 Fax (405) 942-3527 Exhibit 8 September 3, 2003 Atlas Resources, Inc. 311 Rouser Road Moon Township, Pennsylvania 15108 RE: ATLAS AMERICA PUBLIC #12-2003 PROGRAM Gentlemen: You have requested our opinions on the material federal income tax issues pertaining to Atlas America Public #12-2003 Program (the "Program"), a series of up to three natural gas and oil drilling limited partnerships (each a "Partnership" or collectively the "Partnerships"), all of which will be formed under the Delaware Revised Uniform Limited Partnership Act before they begin their drilling activities. We have acted as Special Counsel to the Program with respect to the offering of Units in the Partnerships. Atlas Resources, Inc. will be the Managing General Partner of each of the Partnerships. Capitalized terms used and not otherwise defined in this letter have the respective meanings assigned to them in the form of Agreement of Limited Partnership for the Partnerships (the "Partnership Agreement") included as Exhibit (A) to the Prospectus. Our opinions are based in part on our review of: o the Registration Statement on Form S-1 for the Partnerships as originally filed with the SEC, and amendments to the Registration Statement, including the Prospectus and the Drilling and Operating Agreement and the Partnership Agreement included as exhibits to the Prospectus; o other corporate records, certificates, agreements, instruments and documents as we deemed relevant and necessary to review as a basis for our opinions; and o existing statutes, rulings and regulations as presently interpreted by judicial and administrative bodies, which are subject to change. Any changes in existing law could result in different tax consequences and could render our opinions inapplicable. In addition, many of the material federal income tax consequences of an investment in a Partnership depend in part on determinations which are inherently factual in nature. Thus, in rendering our opinions we have inquired as to all relevant facts and obtained from you representations with respect to certain relevant facts relating to the Partnerships which we have assumed for purposes of our opinions. Based on the foregoing, we are satisfied that our opinions take into account all relevant facts, and that the material facts (including our factual assumptions and your representations) are accurately and completely described in this letter and, where appropriate, in the Prospectus. Any material inaccuracy in your representations may render our opinions inapplicable. Included among your representations are the following: o The Partnership Agreement of each Partnership will be executed by the Managing General Partner and its Participants and recorded in all places required under the Delaware Revised Uniform Limited KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. September 3, 2003 Page 2 Partnership Act and any other applicable limited partnership act. Also, each Partnership, when formed, will be operated as described in the Prospectus and in accordance with the terms of the Partnership Agreement, the Delaware Revised Uniform Limited Partnership Act, and any other applicable limited partnership act. o Each Partnership will be subject to the partnership provisions of the Code and will not elect to be taxed as a corporation. o Each Partnership will own legal title to its Working Interest in all of its Prospects, although initially title to the Prospects will be held in the name of the Managing General Partner, its Affiliates or other third-parties as nominee for the Partnership, in order to facilitate the acquisition of the Leases. o The Drilling and Operating Agreement for each Partnership will be duly executed and will govern the drilling and, if warranted, the completion and operation of the Partnership's wells. o The amounts that will be paid by each Partnership to the Managing General Partner or its Affiliates under the Partnership Agreement are reasonable amounts that ordinarily would be paid for similar services in similar transactions between Persons having no affiliation and dealing with each other "at arms' length," including the amounts that will be paid to the Managing General Partner or its Affiliates under the Drilling and Operating Agreement to drill and complete the Partnership Wells based on information the Managing General Partner has concerning drilling rates of third-party drilling companies in the Appalachian Basin, the estimated costs of non-affiliated persons to drill and equip wells in the Appalachian Basin as reported for 2001 by an independent industry association which surveyed other non-affiliated operators in the area, and information the Managing General Partner has concerning increases in drilling costs in the area since 2001. o Based on the Managing General Partner's experience and its knowledge of industry practices in the Appalachian Basin, the allocation of the drilling and completion price to be paid by each Partnership to the Managing General Partner or its Affiliates as a third-party general drilling contractor to drill and complete a well between Intangible Drilling Costs and Tangible Costs as set forth in the Prospectus and "-Intangible Drilling Costs," below is reasonable. o Depending primarily on when each Partnership's subscriptions are received, the Managing General Partner anticipates that Atlas America Public #12-2003 Limited Partnership will prepay in 2003 most, if not all, of its Intangible Drilling Costs for drilling activities that will begin in 2004. In addition, the Managing General Partner anticipates that Atlas America Public #12-2004(B) Limited Partnership, which may close on December 31, 2004, may prepay in 2004 most, if not all, of its Intangible Drilling Costs for drilling activities that will begin in 2005. o Each Partnership will own only Working Interests in all of its Prospects, and will elect to deduct currently all Intangible Drilling Costs. o Each Partnership will have a calendar year taxable year and use the accrual method of accounting. o Based on the Managing General Partner's experience (see "Prior Activities" in the Prospectus) and the intended operations of each Partnership, the Managing General Partner has determined that the aggregate deductions, including depletion deductions, and 350% of the aggregate credits, if any, which will be claimed by the Managing General Partner and the Participants, will not during the first KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. September 3, 2003 Page 3 five tax years following the funding of any of the Partnerships exceed twice the amounts invested by the Managing General Partner and the Participants, respectively, in any of the Partnerships. Thus, the Managing General Partner will not register any of the Partnerships with the IRS as a "tax shelter." o The Investor General Partner Units in each Partnership will not be converted to Limited Partner Units before all of the wells in the Partnership have been drilled and completed. o The Units of each Partnership will not be traded on an established securities market. o The principal purpose of each Partnership is to locate, produce and market natural gas and oil on a profitable basis apart from tax benefits. o A typical Participant in each Partnership will be a natural person who purchases Units in the offering and is a U.S. citizen. o The Managing General Partner does not anticipate that any of the Partnerships will elect to be treated as an "electing large partnership" under the Code for reporting and audit purposes. o In any administrative or judicial proceedings with the IRS, the Managing General Partner, as Tax Matters Partner, will provide the Participants with notices of the proceedings and other information as required by the Code and the Partnership Agreement. o Each Partnership will provide its Participants with the tax information applicable to their respective investments in the Partnership necessary to prepare their federal, state and local income tax returns. o The Managing General Partner will attempt to eliminate or reduce any gain to a Partnership from a Farmout, if any. We have considered the provisions of 31 CFR, Part 10, ss.10.33 (Treasury Department Circular No. 230) on tax law opinions and this letter fully and fairly addresses all material federal income tax issues associated with an investment in the Units by a typical Participant. We consider material those issues which: o would significantly shelter from federal income taxes a Participant's income from sources other than the Partnership in which he invests by providing deductions in excess of the income from the Partnership in any year; o are expected to be of fundamental importance to a Participant; or o could have a significant impact (whether beneficial or adverse) on a Participant under any reasonably foreseeable circumstances. Also, in ascertaining that all material federal tax issues have been considered, evaluating the merits of those issues, and evaluating whether the federal tax treatment set forth in our opinions is the proper tax treatment, we have not taken into account the possibility that: o a tax return will not be audited; KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. September 3, 2003 Page 4 o an issue will not be raised on audit; or o an issue may be settled. Although our opinions express what we believe a court would probably conclude if presented with the applicable issues, our opinions are only predictions, and are not guarantees, of the outcome of the particular tax issues being addressed. There is no assurance that the IRS will not challenge our interpretations or that the challenge would not be sustained in the courts and cause adverse tax consequences to the Participants. Taxpayers bear the burden of proof to support claimed deductions, and our opinions are not binding on the IRS or the courts. Subject to the foregoing, in our opinion the following tax treatment with respect to a typical Participant is the proper tax treatment and will be upheld on the merits if challenged by the IRS and litigated: (1) Partnership Classification. Each Partnership will be classified as a partnership for federal income tax purposes, and not as a corporation. The Partnerships, as such, will not pay any federal income taxes, and all items of income, gain, loss and deduction of the Partnerships will be reportable by the Partners in the Partnership in which they invest. (See "- Partnership Classification.") (2) Passive Activity Classification. o Generally, the passive activity limitations on losses under ss.469 of the Code will apply to Limited Partners, but will not apply to Investor General Partners before the conversion of Investor General Partner Units to Limited Partner Units. o Each Partnership's income and gain from its natural gas and oil properties which are allocated to its Limited Partners, other than net income and gain in the case of converted Investor General Partners, generally will be characterized as passive activity income which may be offset by passive activity losses. o Income or gain attributable to investments of working capital of each Partnership will be characterized as portfolio income, which cannot be offset by passive activity losses. (See "- Limitations on Passive Activities.") (3) Not a Publicly Traded Partnership. None of the Partnerships will be treated as a publicly traded partnership under the Code. (See "- Limitations on Passive Activities - Publicly Traded Partnership Rules.") (4) Availability of Certain Deductions. Business expenses, including payments for personal services actually rendered in the taxable year in which accrued, which are reasonable, ordinary and necessary and do not include amounts for items such as Lease acquisition costs, organization and syndication fees and other items which are required to be capitalized, are currently deductible. (See "-2003 and 2004 Expenditures," "- Availability of Certain Deductions" and "- Partnership Organization and Offering Costs.") (5) Intangible Drilling Costs. Each Partnership will elect to deduct currently all Intangible Drilling Costs. However, a Participant in a Partnership may elect instead to capitalize and deduct all or part of his share of the Intangible Drilling Costs ratably over a 60 month period as discussed in "- Minimum KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. September 3, 2003 Page 5 Tax - Tax Preferences," below. Subject to the foregoing, Intangible Drilling Costs paid by a Partnership under the terms of bona fide drilling contracts for the Partnership's wells will be deductible in the taxable year in which the payments are made and the drilling services are rendered, assuming the amounts are reasonable consideration based on the Managing General Partner's representations, and subject to certain restrictions summarized below, including basis and "at risk" limitations, and the passive activity loss limitation with respect to the Limited Partners. (See "- Intangible Drilling Costs" and "- Drilling Contracts.") (6) Prepayments of Intangible Drilling Costs. Depending primarily on when each Partnership's subscriptions are received, the Managing General Partner anticipates that Atlas America Public #12-2003 Limited Partnership will prepay in 2003 most, if not all, of its Intangible Drilling Costs for drilling activities that will begin in 2004. In addition, the Managing General Partner anticipates that Atlas America Public #12-2004(B) Limited Partnership, which may close on December 31, 2004, may prepay in 2004 most, if not all, of its Intangible Drilling Costs for drilling activities that will begin in 2005. Assuming that the amounts of any prepaid Intangible Drilling Costs of a Partnership are reasonable consideration based on the Managing General Partner's representations, and based in part on the factual assumptions set forth below, the prepayments of Intangible Drilling Costs will be deductible in the year in which they are made even though all Working Interest owners in the well may not be required to prepay Intangible Drilling Costs, subject to certain restrictions summarized below, including basis and "at risk" limitations, and the passive activity loss limitation with respect to the Limited Partners. (See "- Drilling Contracts.") The foregoing opinion is based in part on the assumptions that: o the Intangible Drilling Costs will be required to be prepaid in the year in which they are made for specified wells under the Drilling and Operating Agreement; o under the Drilling and Operating Agreement the drilling of all of the wells is required to be, and actually is, begun before the close of the 90th day after the close of the taxable year in which the prepayment is made, and the wells are continuously drilled until completed, if warranted, or abandoned; and o the required prepayments are not refundable to the Partnership which made the prepayment and any excess prepayments are applied to Intangible Drilling Costs of substitute wells. (7) Depletion Allowance. The greater of cost depletion or percentage depletion will be available to qualified Participants as a current deduction against their share of the natural gas and oil production income of the Partnership in which they invest, subject to certain restrictions summarized below. (See "- Depletion Allowance.") (8) MACRS. Each Partnership's reasonable costs for equipment placed in the wells which cannot be deducted immediately ("Tangible Costs") will be eligible for cost recovery deductions under the Modified Accelerated Cost Recovery System ("MACRS"), generally over a seven year "cost recovery period," subject to certain restrictions summarized below, including basis and "at risk" limitations, and the passive activity loss limitation in the case of the Limited Partners. Subject to the foregoing, each Partnership will be entitled to an additional first-year depreciation allowance based on 50% of the adjusted basis of its "qualified" Tangible Costs for productive wells which are completed and made capable of production, i.e. placed in service, before January 1, 2005. This KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. September 3, 2003 Page 6 additional first-year depreciation allowance will reduce the Partnership's remaining regular MACRS depreciation allowances beginning with the year in which the wells are placed in service. However, none of the MACRS depreciation deductions for a Partnership's "qualified" Tangible Costs will increase the alternative minimum taxable income of that Partnership's Participants. (See "- Depreciation - Modified Accelerated Cost Recovery System ("MACRS").") (9) Tax Basis of Units. Each Participant's adjusted tax basis in his Units will be increased by his total subscription proceeds. (See "- Tax Basis of Units.") (10) At Risk Limitation on Losses. Each Participant initially will be "at risk" to the full extent of his subscription proceeds, assuming that: o each Participant has an objective to carry on the business of the Partnership in which he invests for profit; o any amount borrowed by a Participant and contributed to a Partnership will not be borrowed from a Person who has an interest in the Partnership, other than as a creditor, or a "related person", as that term is defined in ss.465 of the Code, to a Person, other than the Participant, having an interest in the Partnership, other than as a creditor, and the Participant will be severally, primarily, and personally liable for the borrowed amount; and o no Participant will have protected himself from loss for amounts contributed to the Partnership in which he invests through nonrecourse financing, guarantees, stop loss agreements or other similar arrangements. (See "- 'At Risk' Limitation For Losses.") (11) Allocations. Assuming the effect of the allocations of income, gain, loss and deduction, or items thereof, set forth in the Partnership Agreement, including the allocations of basis and amount realized with respect to natural gas and oil properties, is substantial in light of a Participant's tax attributes that are unrelated to the Partnership in which he invests, the allocations will have "substantial economic effect" and will govern each Participant's distributive share of the items to the extent the allocations do not cause or increase deficit balances in the Participants' Capital Accounts. (See "- Allocations.") (12) Subscription. No gain or loss will be recognized by the Participants on payment of their subscriptions. (13) Profit Motive. Assuming that each Participant has an objective to carry on the business of the Partnership in which he invests for profit, the Partnerships will possess the requisite profit motive under ss.183 of the Code. This opinion is based in part on the results of the previous partnerships sponsored by the Managing General Partner set forth in "Prior Activities" in the Prospectus and the Managing General Partner's representations that each Partnership will be operated as described in the Prospectus and the principal purpose of each Partnership is to locate, produce and market natural gas and oil on a profitable basis apart from tax benefits (which is supported by the geological evaluations and other information for the proposed Prospects for Atlas America Public #12-2003 Limited Partnership included in Appendix A to the Prospectus). (See "- Disallowance of Deductions Under Section 183 of the Code.") KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. September 3, 2003 Page 7 (14) No Tax Shelter Registration. None of the Partnerships is required to register with the IRS as a tax shelter. This opinion is based in part on the Managing General Partner's representations that none of the Partnerships has a tax shelter ratio greater than 2 to 1 and each Partnership will be operated as described in the Prospectus. (See "- Lack of Registration as a Tax Shelter.") (15) Anti-Abuse Rules and Judicial Doctrines. Assuming that each Participant has an objective to carry on the business of the Partnership in which he invests for profit, potentially relevant statutory or regulatory anti-abuse rules and judicial doctrines will not have a material adverse effect on the tax consequences of an investment in a Partnership by a typical Participant as described in our opinions. This opinion is based in part on the results of the previous partnerships sponsored by the Managing General Partner set forth in "Prior Activities" in the Prospectus and the Managing General Partner's representations that each Partnership will be operated as described in the Prospectus and the principal purpose of each Partnership is to locate, produce and market natural gas and oil on a profitable basis apart from tax benefits (which is supported by the geological evaluations and other information for the proposed Prospects for Atlas America Public #12-2003 Limited Partnership included in Appendix A to the Prospectus). (See "-Anti-Abuse Rules and Judicial Doctrines.") (16) Overall Evaluation of Tax Benefits. The tax benefits of each Partnership, in the aggregate, which are a significant feature of an investment in a Partnership by a typical Participant will be realized as contemplated by the Prospectus. This opinion is based on our conclusion that substantially more than half of the material tax benefits of each Partnership, in terms of their financial impact on a typical Participant, will be realized if challenged by the IRS. The discussion in the Prospectus under the caption "MATERIAL FEDERAL INCOME TAX CONSEQUENCES," insofar as it contains statements of federal income tax law, is correct in all material respects. * * * * * * * * * * * * * In General The following is a summary of all of the material federal income tax consequences of the purchase, ownership and disposition of Investor General Partners Units and Limited Partner Units which will apply to typical Participants in a Partnership. However, there is no assurance that the present laws or regulations will not be changed and adversely affect a Participant. The IRS may challenge the deductions claimed by a Partnership or a Participant, or the taxable year in which the deductions are claimed, and no guaranty can be given that the challenge would not be upheld if litigated. The practical utility of the tax aspects of any investment depends largely on each Participant's particular income tax position in the year in which items of income, gain, loss, deduction or credit are properly taken into account in computing his federal income tax liability. In addition, except as otherwise noted, different tax considerations may apply to foreign persons, corporations, partnerships, trusts and other prospective Participants which are not treated as individuals for federal income tax purposes. Also, the treatment of the tax attributes of a Partnership may vary among its Participants. Thus, each Participant is urged to seek qualified, professional assistance in the preparation of his federal, state and local tax returns with specific reference to his own tax situation. Partnership Classification For federal income tax purposes a partnership is not a taxable entity. Thus, the partners, rather than the partnership, receive all items of income, gain, loss, deduction, credit and tax preference from the operations engaged in by the partnership. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. September 3, 2003 Page 8 Under the regulations a business entity with two or more members is classified for federal tax purposes as either a corporation or a partnership. Treas. Reg. ss.301.7701-2(a). The term corporation includes a business entity organized under a State statute which describes the entity as a corporation, body corporate, body politic, joint-stock company or joint-stock association. Treas. Reg. ss.301.7701-2(b). Each Partnership will be formed as a limited partnership under the Delaware Revised Uniform Limited Partnership Act which describes each Partnership as a "partnership." Thus, each Partnership automatically will be classified as a partnership unless it elects to be classified as a corporation. In this regard, the Managing General Partner has represented that none of the Partnerships will elect to be taxed as a corporation. Limitations on Passive Activities Under the passive activity rules of ss.469 of the Code, all income of a taxpayer who is subject to the rules is categorized as: o income from passive activities such as limited partners' interests in a business; o active income such as salary, bonuses, etc.; or o portfolio income. "Portfolio income" consists of: o interest, dividends and royalties unless earned in the ordinary course of a trade or business; and o gain or loss not derived in the ordinary course of a trade or business on the sale of property that generates portfolio income or is held for investment. Losses generated by passive activities can offset only passive income and cannot be applied against active income or portfolio income. The passive activity rules apply to individuals, estates, trusts, closely held C corporations which generally are corporations with five or fewer individuals who own directly or indirectly more than 50% of the stock, and personal service corporations other than corporations where the owner-employees together own less than 10% of the stock. However, a closely held C corporation, other than a personal service corporation, may use passive losses and credits to offset taxable income of the company figured without regard to passive income or loss or portfolio income. Passive activities include any trade or business in which the taxpayer does not materially participate on a regular, continuous, and substantial basis. Under the Partnership Agreement, Limited Partners will not have material participation in the Partnership in which they invest and generally will be subject to the passive activity limitations. Investor General Partners also do not materially participate in the Partnership in which they invest. However, because each Partnership will own only Working Interests in its wells and Investor General Partners will not have limited liability under the Delaware Revised Uniform Limited Partnership Act until they are converted to Limited Partners, their deductions generally will not be treated as passive deductions before the conversion. I.R.C. ss.469(c)(3). (See "- Conversion from Investor General Partner to Limited Partner," below.) However, if an Investor General Partner invests in a Partnership through an entity which limits his liability, for example, a limited partnership in which he is a limited partner, a limited liability company or an S corporation, then he generally will be subject to the passive activity limitations the same as a Limited Partner. Contractual limitations on the liability of Investor General Partners under the KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. September 3, 2003 Page 9 Partnership Agreement such as insurance, limited indemnification, etc. will not cause Investor General Partners to be subject to the passive activity limitations. A Limited Partner's "at risk" amount is reduced by losses allowed under ss.465 of the Code even if the losses are suspended by the passive activity limitations. (See "- `At Risk' Limitation For Losses," below.) Similarly, a Limited Partner's basis is reduced by deductions even if the deductions are suspended under the passive activity limitations. (See "- Tax Basis of Units," below.) Suspended losses may be carried forward indefinitely, but not back, and used to offset future years' passive activity income. A suspended loss is allowed in full when the entire interest in a passive activity is sold to an unrelated third-party in a taxable transaction and in part on the disposition of substantially all of the interest in a passive activity if the suspended loss as well as current gross income and deductions can be allocated to the part disposed of with reasonable certainty. In an installment sale, passive losses become available in the same ratio that gain recognized each year bears to the total gain on the sale. Any suspended losses remaining at a taxpayer's death are allowed as deductions on his final return, subject to a reduction to the extent the basis of the property in the hands of the transferee exceeds the property's adjusted basis immediately before the decedent's death. If a taxpayer makes a gift of his entire interest in a passive activity, the basis in the property of the person receiving the gift is increased by any suspended losses and no deductions are allowed. If the interest is later sold at a loss, the basis in the property of the person receiving the gift is limited to the fair market value on the date the gift was made. Publicly Traded Partnership Rules. Net losses of a partner from each publicly traded partnership are suspended and carried forward to be netted against income from that publicly traded partnership only. In addition, net losses from other passive activities may not be used to offset net passive income from a publicly traded partnership. I.R.C. ss.ss.469(k)(2) and 7704. However, in our opinion none of the Partnerships will be treated as a publicly traded partnership under the Code. Conversion from Investor General Partner to Limited Partner. If a Participant invests in a Partnership as an Investor General Partner, then his share of the Partnership's deduction for Intangible Drilling Costs in the year in which he invests will not be subject to the passive activity limitations because the Investor General Partner Units will not be converted by the Managing General Partner to Limited Partner Units until after all of the Partnership's wells have been drilled and completed. (See "Actions to be Taken by Managing General Partner to Reduce Risks of Additional Payments by Investor General Partners" in the Prospectus and "- Drilling Contracts," below.) After the Investor General Partner Units have been converted to Limited Partner Units, each former Investor General Partner will have limited liability as a limited partner under the Delaware Revised Uniform Limited Partnership Act with respect to his Partnership's activities after the date of the conversion. Concurrently, the former Investor General Partner will become subject to the passive activity limitations as a limited partner. However, the former Investor General Partner previously will have received a non-passive loss as an Investor General Partner in the year in which he invested in the Partnership as a result of the Partnership's deduction for Intangible Drilling Costs. Therefore, the Code requires that his net income from the Partnership Wells after his conversion to a limited partner must continue to be characterized as non-passive income which cannot be offset with passive losses. I.R.C. ss.469(c)(3)(B). An Investor General Partner's conversion of his Investor General Partner Units into Limited Partner Units should not have any other adverse tax consequences unless the Investor General Partner's share of any Partnership liabilities is reduced as a result of the conversion. Rev. Rul. 84-52, 1984-1 C.B. 157. A reduction in a partner's share of liabilities is treated as a constructive distribution of cash to the partner, which reduces the basis of the partner's interest in the partnership and is taxable to the extent it exceeds his basis. (See "-Tax Basis of Units," below.) KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. September 3, 2003 Page 10 Taxable Year and Method of Accounting Taxable Year. Each Partnership intends to adopt a calendar year taxable year. I.R.C. ss.ss.706(a) and (b). The taxable year of a Partnership is important to a Participant because the Partnership's deductions, income and other items of tax significance must be taken into account in computing the Participant's taxable income for his taxable year within or with which the Partnership's taxable year ends. The tax year of a partnership generally must be the tax year of one or more of its partners who have an aggregate interest in partnership profits and capital of greater than 50%. Method of Accounting. Each Partnership will use the accrual method of accounting for federal income tax purposes. I.R.C. ss.448(a). Under the accrual method of accounting, income is taken into account for the year in which all events have occurred which fix the right to receive it and the amount is determinable with reasonable accuracy, rather than the time of receipt. Consequently, Participants may have income tax liability resulting from the Partnership's accrual of income in one tax year that it does not receive until the next tax year. Expenses are deducted for the year in which all events have occurred that determine the fact of the liability, the amount is determinable with reasonable accuracy and the economic performance test is satisfied. Under ss.461(h) of the Code, if the liability of the taxpayer arises out of the providing of services or property to the taxpayer by another person, economic performance occurs as the services or property, respectively, are provided. If the liability of the taxpayer arises out of the use of the property by the taxpayer, economic performance occurs as the property is used. o A special rule in the Code, however, provides that there is economic performance in the current taxable year with respect to amounts paid in that taxable year for intangible drilling costs of drilling a natural gas or oil well so long as the drilling of the well begins before the close of the 90th day after the close of the taxable year. I.R.C.ss.461(i). (See "-Drilling Contracts," below.) 2003 and 2004 Expenditures The Managing General Partner anticipates that all of each Partnership's subscription proceeds will be expended in the year in which its Participants invest in the Partnership and the related income and deductions, including the deduction for Intangible Drilling Costs, will be reflected on the Participants' federal income tax returns for that period. (See "Capitalization and Source of Funds and Use of Proceeds" and "Participation in Costs and Revenues" in the Prospectus.) Depending primarily on when each Partnership's subscription proceeds are received, the Managing General Partner anticipates that Atlas America Public #12-2003 Limited Partnership will prepay in 2003 most, if not all, of its Intangible Drilling Costs for drilling activities that will begin in 2004. In addition, the Managing General Partner anticipates that Atlas America Public #12-2004(B) Limited Partnership, which may close on December 31, 2004, may prepay in 2004 most, if not all, of its Intangible Drilling Costs for drilling activities that will begin in 2005. The deductibility of these advance payments in the year in which a Participant invests in the Partnership cannot be guaranteed. (See "- Drilling Contracts," below.) In addition, wells which are prepaid in 2004 and drilled and completed in 2005, if any, will not be eligible for the additional 50% first-year depreciation deduction discussed in "- Depreciation - Modified Accelerated Cost Recovery System ("MACRS"), below. Availability of Certain Deductions Ordinary and necessary business expenses, including reasonable compensation for personal services actually rendered, are deductible in the year incurred. Treasury Regulation ss.1.162-7(b)(3) provides that reasonable compensation is only the amount as would ordinarily be paid for like services by like enterprises under like KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. September 3, 2003 Page 11 circumstances. The Managing General Partner has represented that the amounts payable to the Managing General Partner and its Affiliates, including the amounts payable to the Managing General Partner or its Affiliates as general drilling contractor, are reasonable amounts which would ordinarily be paid for similar services in similar transactions. (See "- Drilling Contracts," below.) The fees paid to the Managing General Partner and its Affiliates will not be currently deductible to the extent it is determined by the IRS or the courts that they are: o in excess of reasonable compensation; o properly characterized as organization or syndication fees or other capital costs such as the acquisition cost of the Leases; or o not "ordinary and necessary" business expenses. (See " - Partnership Organization and Offering Costs," below.) In the event of an audit, payments to the Managing General Partner and its Affiliates by a Partnership will be scrutinized by the IRS to a greater extent than payments to an unrelated party. Intangible Drilling Costs Assuming a proper election and subject to the passive activity loss rules in the case of Limited Partners, each Participant will be entitled to deduct his share of his Partnership's Intangible Drilling Costs, which include items which do not have salvage value, such as labor, fuel, repairs, supplies and hauling necessary to the drilling of a well. I.R.C. ss.263(c), Treas. Reg. ss.1.612-4(a). (See "Participation in Costs and Revenues" in the Prospectus and "- Limitations on Passive Activities," above.) These deductions are subject to recapture as ordinary income rather than capital gain on the sale or other disposition of the property or a Participant's Units. (See " - Sale of the Properties" and " - Disposition of Units," below.) Also, productive-well Intangible Drilling Costs may subject a Participant to an alternative minimum tax in excess of regular tax unless the Participant elects to deduct all or part of these costs ratably over a 60 month period. (See "- Minimum Tax - Tax Preferences," below.) The Managing General Partner estimates that on average approximately 78% of the total price to be paid by each Partnership for all of its completed wells will be Intangible Drilling Costs which are charged under the Partnership Agreement 100% to its Participants. Also, under the Partnership Agreement not less than 90% of the subscription proceeds received by each Partnership from its Participants will be used to pay Intangible Drilling Costs. The IRS could challenge the characterization of a portion of these costs as deductible Intangible Drilling Costs and recharacterize the costs as some other item which may be nondeductible. However, this would have no effect on the allocation and payment of the Intangible Drilling Costs by the Participants under the Partnership Agreement. In the case of corporations, other than S corporations, which are "integrated oil companies," the amount allowable as a deduction for Intangible Drilling Costs in any taxable year is reduced by 30%. I.R.C. ss.291(b)(1). Integrated oil companies are: o those taxpayers who directly or through a related person engage in the retail sale of natural gas and oil and whose gross receipts for the taxable year from such activities exceed $5,000,000; or o those taxpayers and related persons who have refinery production in excess of 50,000 barrels on any day during the taxable year. I.R.C.ss.291(b)(4). KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. September 3, 2003 Page 12 Amounts disallowed as a current deduction are allowable as a deduction ratably over the 60-month period beginning with the month in which the costs are paid or incurred. The Partnerships will not be integrated oil companies. Each Participant is urged to consult with his personal tax advisor concerning the tax benefits to him of the deduction for Intangible Drilling Costs in the Partnership in which he invests in light of the Participant's own tax situation. Drilling Contracts Each Partnership will enter into the Drilling and Operating Agreement with the Managing General Partner or its Affiliates, as a third-party general drilling contractor, to drill and complete the Partnership's Development Wells on a Cost plus 15% basis. For its services as general drilling contractor, the Managing General Partner anticipates that on average over all of the wells drilled and completed by each Partnership, assuming a 100% Working Interest in each well, it will have reimbursement of general and administrative overhead of $14,142 per well and a profit of 15% (approximately $26,083) per well, with respect to the Intangible Drilling Costs and the portion of Tangible Costs paid by the Participants as described in "Compensation - Drilling Contracts" in the Prospectus. However, the actual cost of drilling and completing the wells may be more or less than the estimated amount, due primarily to the uncertain nature of drilling operations, and the Managing General Partner's profit per well also could be more or less than the dollar amount estimated by the Managing General Partner. The Managing General Partner believes the prices under the Drilling and Operating Agreement are competitive in the proposed areas of operation. Nevertheless, the amount of the profit realized by the Managing General Partner under the Drilling and Operating Agreement could be challenged by the IRS as unreasonable and disallowed as a deductible Intangible Drilling Cost. (See "- Intangible Drilling Costs," above, and "Compensation" and "Proposed Activities" in the Prospectus.) Depending primarily on when each Partnership's subscriptions are received, the Managing General Partner anticipates that Atlas America Public #12-2003 Limited Partnership will prepay in 2003 most, if not all, of its Intangible Drilling Costs for drilling activities that will begin in 2004. In addition, the Managing General Partner anticipates that Atlas America Public #12-2004(B) Limited Partnership, which may close on December 31, 2004, may prepay in 2004 most, if not all, of its Intangible Drilling Costs for drilling activities that will begin in 2005. In Keller v. Commissioner, 79 T.C. 7 (1982), aff'd 725 F.2d 1173 (8th Cir. 1984), the Tax Court applied a two-part test for the current deductibility of prepaid intangible drilling and development costs. The test is: o the expenditure must be a payment rather than a refundable deposit; and o the deduction must not result in a material distortion of income taking into substantial consideration the business purpose aspects of the transaction. The drilling partnership in Keller entered into footage and daywork drilling contracts which permitted it to terminate the contracts at any time without default by the driller, and receive a return of the prepaid amounts less amounts earned by the driller. The Tax Court found that the right to receive, by unilateral action, a refund of the prepayments on the footage and daywork drilling contracts rendered the prepayments deposits instead of payments. Therefore, the prepayments were held to be nondeductible in the year they were paid to the extent they had not been earned by the driller. The Tax Court further found that the drilling partnership failed to show a convincing business purpose for prepayments under the footage and daywork drilling contracts. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. September 3, 2003 Page 13 The drilling partnership in Keller also entered into turnkey drilling contracts which permitted it to stop work under the contract at any time and apply the unearned balance of the prepaid amounts to another well to be drilled on a turnkey basis. The Tax Court found that these prepayments constituted "payments" and not nondeductible deposits, despite the right of substitution. Further, the Tax Court noted that the turnkey drilling contracts obligated "the driller to drill to the contract depth for a stated price regardless of the time, materials or expenses required to drill the well," thereby locking in prices and shifting the risks of drilling from the drilling partnership to the driller. Since the drilling partnership, a cash basis taxpayer, received the benefit of the turnkey obligation in the year of prepayment, the Tax Court found that the amounts prepaid on turnkey drilling contracts clearly reflected income and were deductible in the year of prepayment. In Leonard T. Ruth, TC Memo 1983-586, a drilling program entered into nine separate turnkey contracts with a general contractor, the parent corporation of the drilling program's corporate general partner, to drill nine program wells. Each contract identified the prospect to be drilled, stated the turnkey price, and required the full price to be paid in 1974. The program paid the full turnkey price to the general contractor on December 31, 1974; the receipt of which was found by the court to be significant in the general contractor's financial planning. The program had no right to receive a refund of any of the payments. The actual drilling of the nine wells was subcontracted by the general contractor to independent contractors who were paid by the general contractor in accordance with their individual contracts. The drilling of all wells commenced in 1975 and all wells were completed that year. The amount paid by the general contractor to the independent driller for its work on the nine wells was approximately $365,000 less than the amount prepaid by the program to the general contractor. The program claimed a deduction for intangible drilling and development costs in 1974. The IRS challenged the timing of the deduction, contending that there was no business purpose for the payments in 1974, that the turnkey arrangements were merely "contracts of convenience" designed to create a tax deduction in 1974, and that the turnkey contracts constituted assets having a life beyond the taxable year and that to allow a deduction for their entire costs in 1974 distorted income. The Tax Court, relying on Keller, held that the program could deduct the full amount of the payments in 1974. The court found that the program entered into turnkey contracts, paid a premium to secure the turnkey obligations, and thereby locked in the drilling price and shifted the risks of drilling to the general contractor. Further, the court found that by signing and paying the turnkey obligation, the program got its bargained-for benefit in 1974, therefore the deduction of the payments in 1974 clearly reflected income. Each Partnership will attempt to comply with the guidelines set forth in Keller with respect to any prepaid Intangible Drilling Costs. The Drilling and Operating Agreement will require each Partnership to prepay Intangible Drilling Costs in the year in which the Participant invests for specified wells the drilling of which may begin in the following year. Prepayments should not result in a loss of current deductibility where: o there is a legitimate business purpose for the required prepayment; o the contract is not merely a sham to control the timing of the deduction; and o there is an enforceable contract of economic substance. The Drilling and Operating Agreement will require each Partnership to prepay the Intangible Drilling Costs of drilling and completing its wells in order to enable the Operator to: o begin site preparation for the wells; o obtain suitable subcontractors at the then current prices; and o insure the availability of equipment and materials. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. September 3, 2003 Page 14 Under the Drilling and Operating Agreement excess prepaid amounts, if any, will not be refundable to the Partnership, but will be applied to Intangible Drilling Costs to be incurred in drilling and completing substitute wells. Under Keller, a provision for substitute wells should not result in the prepayments being characterized as refundable deposits. The likelihood that prepayments will be challenged by the IRS on the grounds that there is no business purpose for the prepayment is increased if prepayments are not required with respect to 100% of the Working Interest in the well. It is possible that less than 100% of the Working Interest will be acquired by a Partnership in one or more wells and prepayments may not be required of all owners of Working Interests in the wells. However, in our view, a legitimate business purpose for the required prepayments may exist under the guidelines set forth in Keller, even though prepayment is not required by the drilling contractor with respect to a portion of the Working Interest in the wells. In addition, a current deduction for prepaid Intangible Drilling Costs is available only if the drilling of the wells begins before the close of the 90th day after the close of the taxable year in which the prepayment was made. I.R.C. ss.461(i). (See "- Taxable Year and Method of Accounting," above.) Under the Drilling and Operating Agreement, the Managing General Partner as operator and general drilling contractor will use its best efforts to begin drilling each Partnership's wells before the close of the 90th day after the close of the Partnership's taxable year in which the prepayment was made. However, the drilling of any Partnership Well may be delayed due to circumstances beyond the control of the Managing General Partner or the drilling subcontractors. These circumstances include, for example: o the unavailability of drilling rigs; o decisions of third-party operators to delay drilling the wells; o poor weather conditions; o inability to obtain drilling permits or access right to the drilling site; or o title problems. Due to the foregoing factors, no guaranty is made by the Managing General Partner under the Drilling and Operating Agreement that the drilling of all wells prepaid by a Partnership will actually begin before the close of the 90th day after the close of the Partnership's taxable year in which the prepayment was made. If the drilling of a prepaid Partnership Well does not begin by that date, deductions claimed by a Participant for prepaid Intangible Drilling Costs for the well in the year in which the Participant invests in the Partnership would be disallowed and deferred to the next taxable year when the well is actually drilled. No assurance can be given that on audit the IRS would not disallow the current deductibility of a portion or all of any prepayments of Intangible Drilling Costs under a Partnership's drilling contracts, thereby decreasing the amount of deductions allocable to the Participants in that Partnership for the year in which they invest in that Partnership, or that the challenge would not ultimately be sustained. In the event of disallowance, the deduction for prepaid Intangible Drilling Costs would be available in the next year when the wells are actually drilled. Depletion Allowance Proceeds from the sale of each Partnership's natural gas and oil production will constitute ordinary income. A certain portion of that income will not be taxable under the depletion allowance which permits the deduction from gross income for federal income tax purposes of either the percentage depletion allowance or the cost depletion KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. September 3, 2003 Page 15 allowance, whichever is greater. I.R.C. ss.ss.611, 613 and 613A. These deductions are subject to recapture as ordinary income rather than capital gain on the disposition of the property or a Participant's Units. (See " - Sale of the Properties" and " - Disposition of Units," below.) Cost depletion for any year is determined by dividing the adjusted tax basis for the property by the total units of natural gas or oil expected to be recoverable from the property and then multiplying the resultant quotient by the number of units actually sold during the year. Cost depletion cannot exceed the adjusted tax basis of the property to which it relates. Percentage depletion generally is available to taxpayers other than "integrated oil companies" as that term is defined in "- Intangible Drilling Costs," above, which does not include the Partnerships. Percentage depletion is based on a Participant's share of his Partnership's gross production income from its natural gas and oil properties. Generally, percentage depletion is available with respect to 6 million cubic feet of average daily production of natural gas or 1,000 barrels of average daily production of domestic crude oil. Taxpayers who have both natural gas and oil production may allocate the production limitation between the production. The rate of percentage depletion is 15%. However, percentage depletion for marginal production increases 1%, up to a maximum increase of 10%, for each whole dollar that the domestic wellhead price of crude oil for the immediately preceding year is less than $20 per barrel without adjustment for inflation. I.R.C. ss.613A(c)(6). The term "marginal production" includes natural gas and oil produced from a domestic stripper well property, which is defined as any property which produces a daily average of 15 or less equivalent barrels of oil, which is equivalent to 90 mcf of natural gas, per producing well on the property in the calendar year. Most, if not all, of each Partnership's wells will qualify for these potentially higher rates of percentage depletion. The rate of percentage depletion for marginal production in 2003 is 15%. This rate may fluctuate from year to year depending on the price of oil, but will not be less than the statutory rate of 15% nor more than 25%. Also, percentage depletion: (i) may not exceed 100% of the net income from each natural gas and oil property before the deduction for depletion; and (ii) is limited to 65% of the taxpayer's taxable income for a year computed without regard to percentage depletion, net operating loss carry-backs and capital loss carry-backs. Availability of percentage depletion must be computed separately by each Participant and not by a Partnership or for Participants in a Partnership as a whole. Potential Participants are urged to consult their own tax advisors with respect to the availability of percentage depletion to them. Depreciation - Modified Accelerated Cost Recovery System ("MACRS") Tangible Costs and the related depreciation deductions of each Partnership generally are charged and allocated under the Partnership Agreement 66% to the Managing General Partner and 34% to the Participants in the Partnership. However, if the total Tangible Costs for all of the Partnership's wells that would be charged to the Participants exceeds an amount equal to 10% of the Partnership's subscription proceeds, then the excess, together with the related depreciation deductions, will be charged and allocated to the Managing General Partner. These deductions are subject to recapture as ordinary income rather than capital gain on the disposition of the property or a Participant's Units. (See " - Sale of the Properties" and " - Disposition of Units," below.) The cost of most equipment placed in service by each Partnership will be recovered through depreciation deductions over a seven year cost recovery period using the 200% declining balance method, with a switch to straight-line to maximize the deduction. I.R.C. ss.168(c). In the case of a short tax year the MACRS deduction is prorated on a 12-month basis. No distinction is made between new and used KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. September 3, 2003 Page 16 property and salvage value is disregarded. Except as discussed below, all property assigned to the 7-year class generally is treated as placed in service, or disposed of, in the middle of the year, and depreciation for alternative minimum tax purposes is computed using the 150% declining balance method, switching to straight-line, for most personal property. Notwithstanding the foregoing, under the Jobs and Growth Tax Relief Reconciliation Act of 2003 ("2003 Tax Act"), for federal income tax purposes each Partnership will be entitled to an additional first-year depreciation allowance based on 50% of the adjusted basis of its "qualified" Tangible Costs. For this purpose, a Partnership's "qualified" Tangible Costs means the Partnership's equipment costs for productive wells which are completed and made capable of production, i.e. placed in service, before January 1, 2005. I.R.C. ss.168(k)(2) and (4). Thus, with respect to Atlas America Public #12-2004(B) Limited Partnership, which may close on December 31, 2004, this additional first-year depreciation allowance would not be available for wells, if any, which are prepaid by the Partnership and drilled and completed after January 1, 2005. (See "- Drilling Contracts," above.) The basis of this qualified equipment will be reduced by the additional 50% first-year depreciation allowance for purposes of calculating the regular MACRS depreciation allowances beginning with the year the wells are placed in service. The examples provided in the Technical Explanation of the Job Creation and Worker Assistance Act of 2002 ("2002 Tax Act") which provided a similar accelerated depreciation allowance of 30%, do not reduce the 30% additional depreciation allowance by the half-year convention discussed above. Nevertheless, because this situation is not clearly addressed by either the 2002 Tax Act or the 2003 Tax Act, it is possible that the half-year convention or a mid-quarter convention, depending on when a Partnership's wells are placed in service, ultimately may be determined to apply under the 2003 Tax Act. o Also, a Participant will not incur any alternative minimum tax adjustment with respect to his share of a Partnership's additional 50% first-year depreciation allowance, nor any of its other depreciation deductions for the costs of the qualified equipment it places in the wells. I.R.C.ss.168(k)(2)(F). Lease Acquisition Costs and Abandonment Lease acquisition costs, together with the related cost depletion deduction and any abandonment loss for Lease costs, are allocated under the Partnership Agreement 100% to the Managing General Partner, which will contribute the Leases to each Partnership as a part of its Capital Contribution. Tax Basis of Units A Participant's share of his Partnership's losses is allowable only to the extent of the adjusted basis of his Units at the end of the Partnership's taxable year. I.R.C. ss.704(d). The adjusted basis of the Participant's Units will be adjusted, but not below zero, for any gain or loss to the Participant from a disposition by the Partnership of a natural gas and oil property, and will be increased by his: (i) cash subscription payment; (ii) share of Partnership income; and (iii) share, if any, of Partnership debt. The adjusted basis of a Participant's Units will be reduced by his: (i) share of Partnership losses; (ii) share of Partnership expenditures that are not deductible in computing its taxable income and are not properly chargeable to capital account; KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. September 3, 2003 Page 17 (iii) depletion deductions, but not below zero; and (iv) cash distributions from the Partnership. I.R.C. ss.ss.705, 722 and 742. The reduction in a Participant's share of Partnership liabilities, if any, is considered a cash distribution to the Participant. Although Participants will not be personally liable on any Partnership loans, Investor General Partners will be liable for other obligations of the Partnership. (See "Risk Factors - Risks Related to an Investment In a Partnership - If You Choose to Invest as a General Partner, Then You Have Greater Risk Than a Limited Partner" in the Prospectus.) Should cash distributions to a Participant from his Partnership exceed the tax basis of the Participant's Units, taxable gain would result to the extent of the excess. (See "- Distributions From a Partnership," below.) "At Risk" Limitation For Losses Subject to the limitations on "passive losses" generated by each Partnership in the case of Limited Partners, and a Participant's basis in his Units, each Participant may use his share of his Partnership's losses to offset income from other sources. (See "- Limitations on Passive Activities" and "- Tax Basis of Units," above.) However, a Participant, other than a corporation which is neither an S corporation nor a corporation in which five or fewer individuals own more than 50% of the stock, who sustains a loss in connection with the Partnership's natural gas and oil activities may deduct the loss only to the extent of the amount he has "at risk" in the Partnership at the end of a taxable year. I.R.C. ss.465. A Participant's initial "at risk" amount is limited to the amount of money he pays for his Units. However, any amounts borrowed by a Participant to buy his Units will not be considered "at risk" if the amounts are borrowed from any person who has an interest, other than as a creditor, in the Partnership or from a related person to a person, other than the taxpayer, having such an interest. "Loss" means the excess of allowable deductions for a taxable year from a Partnership over the amount of income actually received or accrued by the Participant during the year from the Partnership. The amount a Participant has "at risk" may not include the amount of any loss that the Participant is protected against through: o nonrecourse loans; o guarantees; o stop loss agreements; or o other similar arrangements. The amount of any loss that is disallowed will be carried over to the next taxable year, to the extent a Participant is "at risk." Further, a Participant's "at risk" amount in subsequent taxable years with respect to a Partnership will be reduced by that portion of the loss which is allowable as a deduction. A Participant's cash subscription payment to the Partnership in which he invests is usually "at risk." Since income, gains, losses, and distributions of the Partnership affect the "at risk" amount, the extent to which a Participant is "at risk" must be determined annually. Previously allowed losses must be included in gross income if the "at risk" amount is reduced below zero. The amount included in income, however, may be deducted in the next taxable year to the extent of any increase in the amount which the Participant has "at risk." KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. September 3, 2003 Page 18 Distributions From a Partnership Generally, a cash distribution from a Partnership to a Participant in excess of the adjusted basis of the Participant's Units immediately before the distribution is treated as gain from the sale or exchange of his Units to the extent of the excess. I.R.C.ss.731(a)(1). No loss is recognized by the Participants on these types of distributions. I.R.C.ss.731(a)(2). No gain or loss is recognized by the Partnership on these types of distributions. I.R.C.ss.731(b). If property is distributed by the Partnership to the Managing General Partner and the Participants, certain basis adjustments may be made by the Partnership, the Managing General Partner and the Participants. I.R.C.ss.ss.732, 733, 734, and 754. (Seess.5.04(d) of the Partnership Agreement.) Other distributions of cash, disproportionate distributions of property, and liquidating distributions of a Partnership may result in taxable gain or loss to the Participants. (See "- Disposition of Units" and " - Termination of a Partnership," below.) Sale of the Properties Under the Jobs and Growth Tax Relief Reconciliation Act of 2003 ("2003 Tax Act"), the maximum tax rates on a noncorporate taxpayer's adjusted net capital gain on the sale of assets held more than a year of 20%, or 10% to the extent it would have been taxed at a 10% or 15% rate if it had been ordinary income, have been reduced to 15% and 5%, respectively, for most capital assets sold or exchanged after May 5, 2003. In addition, for 2008 only, the 5% tax rate on adjusted net capital gain is reduced to 0%. The 2003 Tax Act also eliminated the former maximum tax rates of 18% and 8%, respectively, on qualified five-year gain. I.R.C. ss.1(h). The new capital gain rates also apply for purposes of the alternative minimum tax. I.R.C. ss.55(b)(3). (See " - Minimum Tax - Tax Preferences," below.) However, the former tax rates are scheduled to be reinstated January 1, 2009, as if the 2003 Tax Act had never been enacted. "Adjusted net capital gain" means net capital gain, less certain types of net capital gain that are taxed a maximum rate of 28% (such as gain on the sale of most collectibles and gain on the sale of certain small business stock); or 25% (gain attributable to real estate depreciation). "Net capital gain" means the excess of net long-term gain (excess of long-term gains over long-term losses) over net short-term loss (excess of short-term gains over short-term losses). The annual capital loss limitation for noncorporate taxpayers is the amount of capital gains plus the lesser of $3,000, which is reduced to $1,500 for married persons filing separate returns, or the excess of capital losses over capital gains. I.R.C. ss.1211(b). Gains and losses from sales of natural gas and oil properties held for more than 12 months generally will be treated as a long-term capital gain, while a net loss will be an ordinary deduction, except to the extent of depreciation recapture on equipment and recapture of any Intangible Drilling Costs, depletion deductions and certain losses on previous sales, if any, of a Partnership's assets as discussed below. Other gains and losses on sales of natural gas and oil properties will generally result in ordinary gains or losses. Intangible Drilling Costs that are incurred in connection with a natural gas or oil property may be recaptured as ordinary income when the property is disposed of by a Partnership. Generally, the amount recaptured is the lesser of: o the aggregate amount of expenditures which have been deducted as Intangible Drilling Costs with respect to the property and which, but for being deducted, would be reflected in the adjusted basis of the property; or o the excess of (i) the amount realized, in the case of a sale, exchange or involuntary conversion; or (ii) the fair market value of the interest, in the case of any other disposition; over the adjusted basis of the property. I.R.C.ss.1254(a). (See " - Intangible Drilling Costs," above.) KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. September 3, 2003 Page 19 In addition, the deductions for depletion which reduced the adjusted basis of the property are subject to recapture as ordinary income, and all gain on disposition of equipment is treated as ordinary income to the extent of MACRS deductions claimed by the Partnership. I.R.C. ss.ss.1254(a) and 1245(a). (See " - - Depletion Allowance" and "- Depreciation - Modified Accelerated Cost Recovery System ("MACRS"), above.) Disposition of Units The sale or exchange, including a purchase by the Managing General Partner, of all or part of a Participant's Units held by him for more than 12 months generally will result in a recognition of long-term capital gain or loss. However, previous deductions for depreciation, depletion and Intangible Drilling Costs may be recaptured as ordinary income rather than capital gain regardless of how long the Participant has owned his Units. (See " - Sale of the Properties," above.) If the Units are held for 12 months or less, the gain or loss generally will be short-term gain or loss. Also, a Participant's pro rata share of his Partnership's liabilities, if any, as of the date of the sale or exchange must be included in the amount realized. Therefore, the gain recognized may result in a tax liability to a Participant greater than the cash proceeds, if any, received by the Participant from the disposition. In addition to gain from a passive activity, a portion of any gain recognized by a Limited Partner on the sale or other disposition of his Units will be characterized as portfolio income under ss.469 of the Code to the extent the gain is attributable to portfolio income, e.g. interest on investment of working capital. Treas. Reg. ss.1.469-2T(e)(3). (See " - Limitations on Passive Activities," above.) A gift of a Participant's Units may result in federal and/or state income tax and gift tax liability to the Participant. Also, interests in different partnerships do not qualify for tax-free like-kind exchanges. I.R.C. ss.1031(a)(2)(D). Other dispositions of a Participant's Units may or may not result in recognition of taxable gain. However, no gain should be recognized by an Investor General Partner on the conversion of his Investor General Partner Units to Limited Partner Units so long as there is no change in the Investor General Partner's share of his Partnership's liabilities or certain Partnership assets as a result of the conversion. Rev. Rul. 84-52, 1984-1 C.B. 157. A Participant who sells or exchanges all or part of his Units is required by the Code to notify the Partnership in which he invested within 30 days or by January 15 of the following year, if earlier. I.R.C. ss.6050K. After receiving the notice, the Partnership is required to make a return with the IRS stating the name and address of the transferor and the transferee and any other information as may be required by the IRS. The Partnership must also provide each person whose name is set forth in the return a written statement showing the information set forth on the return. If a Participant dies, sells or exchanges all of his Units, the taxable year of the Partnership in which he invested will close with respect to that Participant, but not the remaining Participants, on the date of death, sale or exchange, with a proration of partnership items for the Partnership's taxable year. I.R.C. ss.706(c)(2). If a Participant sells less than all of his Units, the Partnership's taxable year will not terminate with respect to the selling Participant, but his proportionate share of items of income, gain, loss and deduction will be determined by taking into account his varying interests in the Partnership during the taxable year. Deductions generally may not be allocated to a person acquiring Units from a selling Participant for a period before the purchaser's admission to the Partnership. I.R.C. ss.706(d). Participants are urged to consult their tax advisors before any disposition of a Unit, including purchase of the Unit by the Managing General Partner. Minimum Tax - Tax Preferences With limited exceptions, all taxpayers are subject to the alternative minimum tax. I.R.C. ss.55. If the alternative minimum tax exceeds the regular tax, the excess is payable in addition to the regular tax. The alternative minimum tax is intended to insure that no one with substantial income can avoid tax liability by using exclusions, deductions and KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. September 3, 2003 Page 20 credits. The alternative minimum tax accomplishes this objective by not treating favorably certain items that are treated favorably for purposes of the regular tax. Individual tax preferences or adjustments may include, but are not limited to: accelerated depreciation except as discussed in "-Depreciation - Modified Accelerated Cost Recovery System ("MACRS")" above, Intangible Drilling Costs, incentive stock options and passive activity losses. Generally, the alternative minimum tax rate for individuals is 26% on alternative minimum taxable income up to $175,000, $87,500 for married individuals filing separate returns, and 28% thereafter. See " - Sale of the Properties," above, for the tax rates on capital gains. Regular tax personal exemptions are not available for purposes of the alternative minimum tax. Under the Jobs and Growth Tax Relief Reconciliation Act of 2003, for tax years 2003 and 2004, the exemption amount from alternative minimum tax is increased from $49,000 to $58,000 for married couples filing jointly and surviving spouses; from $35,750 to $40,250 for single filers, and from $24,500 to $29,000 for married persons filing separately. After 2004, the exemption amount for individuals is $45,000 for married couples filing jointly and surviving spouses, $33,750 for single filers, and $22,500 for married persons filing separately. These exemption amounts are reduced by 25% of the alternative minimum taxable income in excess of: o $150,000 for joint returns and surviving spouses; o $75,000 for married persons filing separately; and o $112,500 for single taxpayers. Also, for 2003 and 2004, married persons filing separately must increase their alternative minimum taxable income by the lesser of: (i) 25% of the excess of alternative minimum taxable income over $191,000; or (ii) $29,000. After 2004, married individuals filing separately must increase alternative minimum taxable income by the lesser of: (i) 25% of the excess of alternative minimum taxable income over $165,000; or (ii) $22,500. The only itemized deductions allowed for minimum tax purposes are those for casualty and theft losses, gambling losses to the extent of gambling gains, charitable deductions, medical deductions in excess of 10% of adjusted gross income, qualified housing interest, investment interest expense not exceeding net investment income, and certain estate taxes. The net operating loss for alternative minimum tax purposes generally is the same as for regular tax purposes, except: o current year tax preference items are added back to taxable income; and o individuals may use only those itemized deductions as modified under ss.172(d) of the Code allowable in computing alternative minimum taxable income. Code sections suspending losses, such as the rules concerning a Participant's "at risk" amount and his basis in his Units, are recomputed for alternative minimum tax purposes, and the amount of the deductions suspended or recaptured may differ for regular and alternative minimum tax purposes. Alternative minimum taxable income generally is taxable income, plus or minus various adjustments, plus preferences. For taxpayers other than "integrated oil companies" as that term is defined in "- Intangible Drilling Costs," above, which does not include the Partnerships, the 1992 National Energy Bill repealed: o the preference for excess Intangible Drilling Costs; and o the excess percentage depletion preference for natural gas and oil. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. September 3, 2003 Page 21 The repeal of the excess Intangible Drilling Costs preference, however, under current law may not result in more than a 40% reduction in the amount of the taxpayer's alternative minimum taxable income computed as if the excess Intangible Drilling Costs preference had not been repealed. I.R.C. ss.57(a)(2)(E). Under the prior rules, the amount of Intangible Drilling Costs which is not deductible for alternative minimum tax purposes is the excess of the "excess intangible drilling costs" over 65% of net income from natural gas and oil properties. Net natural gas and oil income is determined for this purpose without subtracting excess Intangible Drilling Costs. Excess Intangible Drilling Costs is the regular Intangible Drilling Costs deduction minus the amount that would have been deducted under 120-month straight-line amortization, or, at the taxpayer's election, under the cost depletion method. There is no preference item for costs of nonproductive wells. Also, each Participant may elect under ss.59(e) of the Code to capitalize all or part of his share of his Partnership's Intangible Drilling Costs and deduct the costs ratably over a 60-month period beginning with the month in which the costs were paid or incurred. This election also applies for regular tax purposes and can be revoked only with the IRS' consent. Making this election, therefore, generally will result in the following consequences to the Participant: o the Participant's regular tax deduction for Intangible Drilling Costs in the year in which he invests will be reduced because the Participant must spread the deduction for the amount of Intangible Drilling Costs which the Participant elects to capitalize over the 60-month amortization period; and o the capitalized Intangible Drilling Costs will not be treated as a preference that is included in the Participant's alternative minimum taxable income. Potential Participants are urged to consult with their personal tax advisors as to the likelihood of the Participant incurring, or increasing, any alternative minimum tax liability because of an investment in a Partnership. Limitations on Deduction of Investment Interest Investment interest expense is deductible by a noncorporate taxpayer only to the extent of net investment income each year, with an indefinite carryforward of disallowed investment interest. I.R.C. ss.163. Investment interest expense generally includes all interest on debt not incurred in a person's active trade or business except consumer interest, qualified residence interest, and passive activity interest under ss.469 of the Code. Accordingly, an Investor General Partner's share of any interest expense incurred by his Partnership before his Investor General Partner Units are converted to Limited Partner Units will be subject to the investment interest limitation. In addition, an Investor General Partner's income and losses, including Intangible Drilling Costs, from the Partnership will be considered investment income and losses for purposes of this limitation. Losses allocable to an Investor General Partner will reduce his net investment income and may affect the deductibility of his investment interest expense, if any. Net investment income is the excess of investment income over investment expenses. Investment income generally includes: o gross income from interest, rents, and royalties; o any excess of net gain from dispositions of investment property over net capital gain determined by gains and losses from dispositions of investment property, and any portion of the net capital gain or net gain, if less, that the taxpayer elects to include in investment income; o portfolio income under the passive activity rules, which includes working capital investment income; KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. September 3, 2003 Page 22 o dividends that do not qualify to be taxed at capital gain rates and dividends that the taxpayer elects to treat as not qualified to be taxed at capital gain rates; and o income from a trade or business in which the taxpayer does not materially participate if the activity is not a "passive activity" under ss.469 of the Code. In the case of Investor General Partners, this includes the Partnership in which he invests before the conversion of Investor General Partner Units to Limited Partner Units, and possibly Partnership net income allocable to former Investor General Partners after they are converted to Limited Partners. Investment expenses include deductions, other than interest, that are directly connected with the production of net investment income, including actual depreciation or depletion deductions allowable. Investment income and investment expenses do not include income or expense taken into account in computing income or loss from a passive activity under ss.469 of the Code. (See "-Limitations on Passive Activities," above.) Allocations The Partnership Agreement allocates to each Participant his share of his Partnership's income, gains, losses and deductions, including the deductions for Intangible Drilling Costs and depreciation. Allocations of certain items are made in ratios that are different than allocations of other items. (See "Participation in Costs and Revenues" in the Prospectus.) The Capital Accounts of the Participants are adjusted to reflect these allocations and the Capital Accounts, as adjusted, will be given effect in distributions made to the Participants on liquidation of the Partnership or any Participant's Units. Generally, the basis of natural gas and oil properties owned by the Partnership for computation of cost depletion and gain or loss on disposition will be allocated and reallocated when necessary in the ratio in which the expenditure giving rise to the tax basis of each property was charged as of the end of the year. (See ss.5.03(b) of the Partnership Agreement.) Generally, a Participant's Capital Account is increased by: o the amount of money he contributes to the Partnership in which he invests; and o allocations to him of income and gain; and decreased by: o the value of property or cash distributed to him; and o allocations to him of loss and deductions. The regulations also require that there must be a reasonable possibility that the allocation will affect substantially the dollar amounts to be received by the partners from the partnership, independent of tax consequences. Allocations made in a manner that is disproportionate to the respective interests of the partners in a partnership of any item of partnership income, gain, loss, deduction or credit will not be given effect unless the allocation has "substantial economic effect." I.R.C. ss.704(b). An allocation generally will have economic effect if throughout the term of a partnership: o the partners' capital accounts are maintained in accordance with rules set forth in the regulations, which generally are based on tax accounting principles; KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. September 3, 2003 Page 23 o liquidation proceeds are distributed in accordance with the partners' capital accounts; and o any partner with a deficit balance in his capital account following the liquidation of his interest in the partnership is required to restore the amount of the deficit to the partnership. Even though the Participants in each Partnership are not required under the Partnership Agreement to restore deficit balances in their Capital Accounts with additional Capital Contributions, an allocation which is not attributable to nonrecourse debt still will be considered under the regulations to have economic effect to the extent it does not cause or increase a deficit balance in a Participant's Capital Account if: o the Partners' Capital Accounts are maintained in accordance with rules set forth in the regulations, which generally are based on tax accounting principles; o liquidation proceeds are distributed in accordance with the Partners' Capital Accounts; and o the Partnership Agreement provides that a Participant who unexpectedly incurs a deficit balance in his Capital Account because of certain adjustments, allocations, or distributions will be allocated income and gain sufficient to eliminate the deficit balance as quickly as possible. Treas. Reg. ss.1.704-l(b)(2)(ii)(d). These provisions are included in the Partnership Agreement (See ss.ss.5.02, 5.03(h), and 7.02(a) of the Partnership Agreement.) Special provisions apply to deductions related to nonrecourse debt. If the Managing General Partner or an Affiliate makes a nonrecourse loan to a Partnership ("partner nonrecourse liability"), Partnership losses, deductions, or ss.705(a)(2)(B) expenditures attributable to the loan must be allocated to the Managing General Partner. Also, if there is a net decrease in partner nonrecourse liability minimum gain with respect to the loan, the Managing General Partner must be allocated income and gain equal to the net decrease. (See ss.ss.5.03(a)(1) and 5.03(i) of the Partnership Agreement.) In the event of a sale or transfer of a Participant's Unit, the death of a Participant, or the admission of an additional Participant, Partnership income, gain, loss and deductions generally will be allocated among the Participants according to their varying interests in the Partnership in which they invest during the taxable year. In addition, in the discretion of the Managing General Partner, Partnership property may be revalued on the admission of additional Participants, or if certain distributions are made to the Participants, to reflect unrealized income, gain, loss or deduction, inherent in the Partnership's property for purposes of adjusting the Participants' Capital Accounts. It should also be noted that each Participant's share of items of income, gain, loss and deduction in the Partnership in which he invests must be taken into account by him whether or not there is any distributable cash. A Participant's share of Partnership revenues applied by his Partnership to the repayment of loans or the reserve for plugging wells, for example, will be included in his gross income in a manner analogous to an actual distribution of the income to him. Thus, a Participant may have tax liability on taxable income from his Partnership for a particular year in excess of any cash distributions from the Partnership to him with respect to that year. To the extent a Partnership has cash available for distribution, however, it is the Managing General Partner's policy that Partnership distributions will not be less than the Managing General Partner's estimate of the Participants' income tax liability with respect to that Partnership's income. If any allocation under the Partnership Agreement is not recognized for federal income tax purposes, each Participant's share of the items subject to the allocation generally will be determined in accordance with his interest in the Partnership in which he invests, determined by considering relevant facts and circumstances. To the extent KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. September 3, 2003 Page 24 deductions allocated by the Partnership Agreement exceed deductions which would be allowed under a reallocation by the IRS, Participants may incur a greater tax burden. However, assuming the effect of the allocations set forth in the Partnership Agreement is substantial in light of a Participant's tax attributes that are unrelated to the Partnership in which he invests, in our opinion the allocations will have "substantial economic effect" and will govern each Participant's share of those items to the extent the allocations do not cause or increase deficit balances in the Participants' Capital Accounts. Partnership Borrowings Under the Partnership Agreement the Managing General Partner and its Affiliates may make loans to the Partnerships. The use of Partnership revenues taxable to Participants to repay borrowings by their Partnership could create income tax liability for the Participants in excess of cash distributions to them from the Partnership, since repayments of principal are not deductible for federal income tax purposes. In addition, interest on the loans will not be deductible unless the loans are bona fide loans that will not be treated as Capital Contributions. In Revenue Ruling 72-135, 1972-1 C.B. 200, the IRS ruled that a nonrecourse loan from a general partner to a partnership engaged in natural gas and oil exploration represented a capital contribution by the general partner rather than a loan. Whether a "loan" by the Managing General Partner or its Affiliates to a Partnership represents in substance debt or equity is a question of fact to be determined from all the surrounding facts and circumstances. Partnership Organization and Offering Costs Expenses connected with the issuance and sale of the Units in the Partnerships, such as promotional expense, the Dealer-Manager fee, Sales Commissions, reimbursements to the Dealer-Manager and other selling expenses, professional fees, and printing costs, which are charged under the Partnership Agreement 100% to the Managing General Partner as Organization and Offering Costs, are not deductible. However, expenses incident to the creation of a partnership may be amortized over a period of not less than 60 months. These amortizable organization expenses also will be paid by the Managing General Partner as part of each Partnership's Organization and Offering Costs. Thus, any related deductions, which the Managing General Partner does not anticipate will be material in amount, will be allocated to the Managing General Partner. I.R.C. ss.709; Treas. Reg. ss.ss.1.709-1 and 2. Tax Elections Each Partnership may elect to adjust the basis of its Partnership property on the transfer of a Unit in the Partnership by sale or exchange or on the death of a Participant, and on the distribution of property by the Partnership to a Participant (the ss.754 election). The general effect of this election is that transferees of the Units are treated, for purposes of depreciation and gain, as though they had acquired a direct interest in the Partnership assets and the Partnership is treated for these purposes, on certain distributions to the Participants, as though it had newly acquired an interest in the Partnership assets and therefore acquired a new cost basis for the assets. Any election, once made, may not be revoked without the consent of the IRS. Each Partnership also may make various elections for federal tax reporting purposes which could result in various items of income, gain, loss and deduction being treated differently for tax purposes than for accounting purposes. Code ss.195 permits taxpayers to elect to capitalize and amortize "start-up expenditures" over a 60-month period. These items include amounts: KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. September 3, 2003 Page 25 o paid or incurred in connection with: o investigating the creation or acquisition of an active trade or business; o creating an active trade or business; or o any activity engaged in for profit and for the production of income before the day on which the active trade or business begins, in anticipation of the activity becoming an active trade or business; and o which would be allowed as a deduction if paid or incurred in connection with the expansion of an existing business. Start-up expenditures do not include amounts paid or incurred in connection with the sale of the Units. If it is ultimately determined by the IRS or the courts that any of a Partnership's expenses constituted start-up expenditures, the Partnership's deductions for those expenses would be deferred over the 60-month period. Disallowance of Deductions Under Section 183 of the Code Under ss.183 of the Code, a Participant's ability to deduct his share of his Partnership's losses on his federal income tax return could be lost if the Partnership lacks the appropriate profit motive as determined from an examination of all facts and circumstances at the time. Section 183 of the Code creates a presumption that an activity is engaged in for profit if, in any three of five consecutive taxable years, the gross income derived from the activity exceeds the deductions attributable to the activity. Thus, if a Partnership in which a Participant invests fails to show a profit in at least three out of five consecutive years this presumption will not be available and the possibility that the IRS could successfully challenge the Partnership deductions claimed by the Participant would be substantially increased. The fact that the possibility of ultimately obtaining profits is uncertain, standing alone, does not appear to be sufficient grounds for the denial of losses under ss.183. (See Treas. Reg. ss.1.183-2(c), Example (5).) In our opinion the Partnerships will possess the requisite profit motive. This opinion assumes that each Participant has an objective to carry on the business of the Partnership in which he invests for profit, and is based in part on the results of the previous partnerships sponsored by the Managing General Partner set forth in "Prior Activities" in the Prospectus and the Managing General Partner's representations that each Partnership will be operated as described in the Prospectus and the principal purpose of each Partnership is to locate, produce and market natural gas and oil on a profitable basis apart from tax benefits (which is supported by the geological evaluations and other information for the proposed Prospects for Atlas America Public #12-2003 Limited Partnership included in Appendix A to the Prospectus). Termination of a Partnership Under ss.708(b) of the Code, a Partnership will be considered as terminated for federal income tax purposes if within a 12 month period there is a sale or exchange of 50% or more of the total interest in Partnership capital and profits. The closing of the Partnership year may result in more than 12 months' income or loss of the Partnership being allocated to certain Participants for the year of termination, for example, Participants using fiscal years other than the calendar year. Under ss.731 of the Code, a Participant will realize taxable gain on a termination of a Partnership to the extent that money regarded as distributed to him exceeds the adjusted basis of his Units. The conversion of Investor General Partner Units to Limited Partner Units, however, will not terminate a Partnership. Rev. Rul. 84-52, 1984-1 C.B. 157. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. September 3, 2003 Page 26 Lack of Registration as a Tax Shelter Section 6111 of the Code generally requires an organizer of a "tax shelter" to register the tax shelter with the Secretary of the Treasury, and to obtain an identification number which must be included on the tax returns of investors in the tax shelter. For this purpose, a "tax shelter" generally is defined to include an investment with respect to which any person could reasonably infer that the ratio that: o the aggregate amount of the potentially allowable deductions and 350% of the potentially allowable credits with respect to the investment during the first five years of the investment bears to; o the amount of money and the adjusted basis of property contributed to the investment; exceeds 2 to 1. In this regard, the Managing General Partner has determined that none of the Partnerships has a tax shelter ratio greater than 2 to 1. Accordingly, the Managing General Partner does not intend to register any of the Partnerships with the IRS as a tax shelter. If it is subsequently determined by the IRS or the courts that the Partnerships were required to be registered with the IRS as a tax shelter, the Managing General Partner would be subject to certain penalties, including a penalty of 1% of the aggregate amount invested in each Partnership for failing to register and $100 for each failure to furnish a Participant a tax shelter registration number. Also, each Participant would be liable for a $250 penalty for failure to include a tax shelter registration number for the Partnership in which he invests on his tax return unless the failure was due to reasonable cause. A Participant also would be liable for a penalty of $100 for failing to furnish the tax shelter registration number to any transferee of his Units. However, in our opinion none of the Partnerships is required to register with the IRS as a tax shelter. This opinion is based in part on the Managing General Partner's representations that none of the Partnerships has a tax shelter ratio greater than 2 to 1 and each Partnership will be operated as described in the Prospectus. Issuance of a registration number does not indicate that an investment or the claimed tax benefits have been reviewed, examined, or approved by the IRS. Investor Lists Section 6112 of the Code requires that if requested by the IRS each Partnership must identify its Participants and provide the IRS with certain information concerning each Participant's investment in the Partnership and tax benefits from the investment, even though the Partnership is not registered with the IRS as a tax shelter. Tax Returns and Audits In General. The tax treatment of all partnership items generally is determined at the partnership, rather than the partner, level; and the partners generally are required to treat partnership items on their individual returns in a manner which is consistent with the treatment of the partnership items on the partnership return. I.R.C.ss.ss.6221 and 6222. Regulations define "partnership items" for this purpose as including distributive share items that must be allocated among the partners, such as partnership liabilities, data pertaining to the computation of the depletion allowance, and guaranteed payments. Treas. Reg.ss.301.6231(a)(3)-1. Generally, the IRS must conduct an administrative determination as to partnership items at the partnership level before conducting deficiency proceedings against a partner, and the partners must file a request for an administrative determination before filing suit for any credit or refund. The period for assessing tax against the Participants attributable KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. September 3, 2003 Page 27 to a partnership item may be extended by agreement between the IRS and the Managing General Partner, which will serve as each Partnership's representative ("Tax Matters Partner") in all administrative and judicial proceedings conducted at the partnership level. The Tax Matters Partner generally may enter into a settlement on behalf of, and binding on, any Participant owning less than a 1% profits interest if there are more than 100 partners in a Partnership. In addition, a partnership with at least 100 partners may elect to be governed under simplified tax reporting and audit rules as an "electing large partnership." I.R.C. ss.775. These rules also facilitate the matching of partnership items with individual partner tax returns by the IRS. The Managing General Partner does not anticipate that the Partnerships will make this election. By executing the Partnership Agreement, each Participant agrees that he will not form or exercise any right as a member of a notice group and will not file a statement notifying the IRS that the Tax Matters Partner does not have binding settlement authority. All expenses of any proceedings undertaken by the Managing General Partner as Tax Matters Partner, which might be substantial, will be paid for by the Partnership being audited. The Managing General Partner is not obligated to contest adjustments made by the IRS. Tax Returns. A Participant's income tax returns are the responsibility of the Participant. Each Partnership will provide its Participants with the tax information applicable to their investment in the Partnership necessary to prepare their tax returns. Penalties and Interest In General. Interest is charged on underpayments of tax, and various civil and criminal penalties are included in the Code. Penalty for Negligence or Disregard of Rules or Regulations. If any portion of an underpayment of tax is attributable to negligence or disregard of rules or regulations, 20% of that portion is added to the tax. Negligence is strongly indicated if a Participant fails to treat partnership items on his tax return in a manner that is consistent with the treatment of those items on the Partnership's return or to notify the IRS of the inconsistency. The term "disregard" includes any careless, reckless or intentional disregard of rules or regulations. There is no penalty, however, if the position (other than negligence) is adequately disclosed and has at least a reasonable basis, or the position is taken with reasonable cause and in good faith, or the position is contrary to an IRS ruling or notice but has a realistic possibility of being sustained on its merits. Treas. Reg. ss.ss.1.6662-3 and 1.6662-7. Valuation Misstatement Penalty. There is an addition to tax of 20% of the amount of any underpayment of tax of $5,000 or more, $10,000 in the case of corporations other than S corporations or personal holding companies, which is attributable to a substantial valuation misstatement. There is a substantial valuation misstatement if: o the value or adjusted basis of any property claimed on a return is 200% or more of the correct amount; or o the price for any property or services, or for the use of property, claimed on a return is 200% or more, or 50% or less, of the correct price. If there is a gross valuation misstatement, which is 400% or more of the correct value or adjusted basis or the undervaluation is 25% or less of the correct amount, then the penalty is 40%. I.R.C.ss.6662(e) and (h). Substantial Understatement Penalty. There is also an addition to tax of 20% of any underpayment if the difference between the tax required to be shown on the return over the tax actually shown on the return exceeds the greater of: KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. September 3, 2003 Page 28 o 10% of the tax required to be shown on the return; or o $5,000, $10,000 in the case of corporations other than S corporations or personal holding companies. I.R.C. ss.6662(d). The amount of any understatement generally will be reduced to the extent it is attributable to the tax treatment of an item: o supported by substantial authority; or o adequately disclosed on the taxpayer's return and there was a reasonable basis for the tax treatment. However, in the case of "tax shelters," which includes each Partnership for this purpose, the understatement may be reduced only if the tax treatment of an item attributable to a tax shelter was supported by substantial authority and the taxpayer establishes that he reasonably believed that the tax treatment claimed was more likely than not the proper treatment. I.R.C. ss.6662(d)(2)(C). Disclosure of partnership items should be made on each Partnership's return; however, a Participant also may make adequate disclosure on his individual return with respect to pass-through items from the Partnership in which he invests. Anti-Abuse Rules and Judicial Doctrines. We have considered the possible application to each Partnership and its intended activities of all potentially relevant statutory and regulatory anti-abuse rules and judicial doctrines. In doing so, we have taken into account the Participants' non-tax purposes (e.g. cash distributions and portfolio diversification) and tax purposes (e.g. Intangible Drilling Costs and depreciation deductions, and the depletion allowance) for investing in a Partnership, and the relative weight of these purposes. We have also taken into account the Managing General Partner's purposes for structuring each Partnership in the manner in which it is structured (e.g. to help the Partnership produce a profit for its Participants and enhance the tax benefits of their investment in a Partnership). Statutory and Regulatory Anti-Abuse Rules. Under Treas. Reg. ss.1.701-2, if a principal purpose of a partnership is to reduce substantially the partners' federal income tax liability in a manner that is inconsistent with the intent of the partnership rules of the Code, based on all the facts and circumstances, the IRS is authorized to remedy the abuse. For illustration purposes, the following factors may indicate that a partnership is being used in a prohibited manner: o the partners' aggregate federal income tax liability is substantially less than had the partners owned the partnership's assets and conducted its activities directly; o the partners' aggregate federal income tax liability is substantially less than if purportedly separate transactions are treated as steps in a single transaction; o one or more partners are needed to achieve the claimed tax results and have a nominal interest in the partnership or are substantially protected against risk; o substantially all of the partners are related to each other; o income or gain are allocated to partners who are not expected to have any federal income tax liability; KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. September 3, 2003 Page 29 o the benefits and burdens of ownership of property nominally contributed to the partnership are retained in substantial part by the contributing party; and o the benefits and burdens of ownership of partnership property are in substantial part shifted to the distributee partners before or after the property is actually distributed to the distributee partners. Judicial Doctrines. We also have considered the possible application to each Partnership and its intended activities of all potentially relevant judicial doctrines including those set forth below. o Step Transactions. This doctrine is that where a series of transactions would give one tax result if viewed independently, but a different tax result if viewed together, then the separate transactions may be combined by the IRS. o Business Purpose. This doctrine involves a determination of whether the taxpayer has a business purpose, other than tax avoidance, for engaging in the transaction, i.e. a "profit objective." o Economic Substance. This doctrine requires a determination of whether, from an objective viewpoint, a transaction is likely to produce economic benefits in addition to tax benefits, and involves a comparison of the potential economic return with the investment made. This test is met when there is a realistic potential for profit when the investment is made, in accordance with the standards applicable to the relevant industry, so that a reasonable businessman, using those standards, would make the investment. o Substance Over Form. This doctrine holds that the substance of the transaction, rather than the form in which it is cast, governs. It applies where the taxpayer seeks to characterize a transaction as one thing, rather than another thing which has different tax results. Under this doctrine, the transaction must have practical economical benefits other than the creation of income tax losses. o Sham Transactions. Under this doctrine, a transaction lacking economic substance may be ignored for tax purposes. Economic substance requires that there be business realities and tax-independent considerations, rather than just tax-avoidance features, i.e. the transaction must have a reasonable objective possibility of providing a profit aside from tax benefits. Shams would include, for example, transactions entered into solely to reduce taxes, which is not a profit motive because there is no intent to produce taxable income. In our opinion potentially relevant statutory or regulatory anti-abuse rules and judicial doctrines will not have a material adverse effect on the tax consequences of an investment in a Partnership by a typical Participant as described in our opinions. This opinion assumes that each Participant has an objective to carry on the business of the Partnership in which he invests for profit, and is based in part on the results of the previous partnerships sponsored by the Managing General Partner set forth in "Prior Activities" in the Prospectus and the Managing General Partner's representations that each Partnership will be operated as described in the Prospectus and the principal purpose of each Partnership is to locate, produce and market natural gas and oil on a profitable basis apart from tax benefits (which is supported by the geological evaluations and other information for the proposed Prospects for Atlas America Public #12-2003 Limited Partnership included in Appendix A to the Prospectus). KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. September 3, 2003 Page 30 State and Local Taxes Under Pennsylvania law each Partnership is required to withhold state income tax at the rate of 2.8% of Partnership income allocable to its Participants who are not residents of Pennsylvania. This requirement does not obviate Pennsylvania tax return filing requirements for Participants who are not residents of Pennsylvania. In the event of overwithholding, a Pennsylvania income tax return must be filed by Participants who are not residents of Pennsylvania in order to obtain a refund. Each Partnership will operate in states and localities which impose a tax on its assets or its income, or on each of its Participants. Deductions which may be available to Participants for federal income tax purposes, such as the accelerated 50% first-year depreciation deduction discussed in "-Depreciation - Modified Accelerated Cost Recovery System ("MACRS") above, may not be available for state or local income tax purposes. A Participant's distributive share of the net income or net loss of the Partnership in which he invests generally must be included in determining his reportable income for state or local tax purposes in the jurisdiction in which he is a resident. To the extent that a non-resident Participant pays tax to a state because of Partnership operations within that state, he may be entitled to a deduction or credit against tax owed to his state of residence with respect to the same income. To the extent that the Partnership operates in certain jurisdictions, state or local estate or inheritance taxes may be payable on the death of a Participant in addition to taxes imposed by his own domicile. Prospective Participants are urged to consult with their own tax advisors concerning the possible effect of various state and local taxes on their personal tax situations. Severance and Ad Valorem (Real Estate) Taxes Each Partnership may incur various ad valorem or severance taxes imposed by state or local taxing authorities. Social Security Benefits and Self-Employment Tax A Limited Partner's share of income or loss from a Partnership is excluded from the definition of "net earnings from self-employment." No increased benefits under the Social Security Act will be earned by Limited Partners and if any Limited Partners are currently receiving Social Security benefits, their shares of Partnership taxable income will not be taken into account in determining any reduction in benefits because of "excess earnings." An Investor General Partner's share of income or loss from a Partnership will constitute "net earnings from self-employment" for these purposes. I.R.C. ss.1402(a). The ceiling for social security tax of 12.4% in 2003 is $87,000 and the ceiling for 2004 is not yet known. There is no ceiling for medicare tax of 2.9%. Self-employed individuals can deduct one-half of their self-employment tax. Farmouts Under a Farmout by a Partnership, if a property interest, other than an interest in the drilling unit assigned to the Partnership Well in question, is earned by the farmee (anyone other than the Partnership) from the farmor (the Partnership) as a result of the farmee drilling or completing the well, then the farmee must recognize income equal to the fair market value of the outside interest earned, and the farmor must recognize gain or loss on a deemed sale equal to the difference between the fair market value of the outside interest and the farmor's tax basis in the outside interest. Neither the farmor nor the farmee would have received any cash to pay the tax. The Managing General Partner will attempt to eliminate or reduce any gain to the Partnership from a Farmout, if any. However, if the IRS claims that a Farmout by a Partnership results in taxable income to the Partnership and its position is ultimately sustained, the Participants in that KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. September 3, 2003 Page 31 Partnership would be required to include their share of the resulting taxable income on their respective personal income tax returns, even though the Partnership and the Participants received no cash from the Farmout. Foreign Partners Each Partnership generally will be required to withhold and pay income tax to the IRS at the highest rate under the Code applicable to Partnership income allocable to its foreign Participants, even if no cash distributions are made to them. A purchaser of a foreign Participant's Units may be required to withhold a portion of the purchase price and the Managing General Partner may be required to withhold with respect to taxable distributions of real property to a foreign Participant. These withholding requirements do not obviate United States tax return filing requirements for foreign Participants. In the event of overwithholding a foreign Participant must file a United States tax return to obtain a refund. Under the Code, for withholding purposes, a foreign partner means a partner who is a nonresident alien individual or a foreign corporation, partnership, trust or estate, if the partner has not certified to the partnership the partner's nonforeign status. Estate and Gift Taxation There is no federal tax on lifetime or testamentary transfers of property between spouses. The gift tax annual exclusion in 2003 is $11,000 per donee which will be adjusted in subsequent years for inflation. Under the Economic Growth and Tax Relief Reconciliation Act of 2001 (the "2001 Tax Act"), the maximum estate and gift tax rate of 49% in 2003 will be 48% in 2004 and will be further reduced in stages until it is 45% from 2007 to 2009. Estates of $1 million in 2003 and $1.5 million in 2004, which further increases in stages to $3.5 million by 2009, or less generally are not subject to federal estate tax. Under the 2001 Tax Act, the federal estate tax will be repealed in 2010, and the maximum gift tax rate in 2010 will be 35%. In 2011 the federal estate and gift taxes are scheduled to be reinstated under the rules in effect before the 2001 Tax Act was enacted. Changes in the Law A Participant's investment in a Partnership may be affected by changes in the tax laws. For example, under the Jobs and Growth Tax Relief Reconciliation Act of 2003, the top four federal income tax brackets for individuals have been reduced, including reducing the top bracket to 35% from 38.6%. These changes are retroactive to January 1, 2003, and are scheduled to expire December 31, 2010. The lower federal income tax rates will reduce to some degree the amount of taxes a Participant saves by virtue of his share of his Partnership's deductions for Intangible Drilling Costs, depletion and depreciation. However, the lower federal income tax rates also will reduce the amount of federal income tax liability incurred by a Participant on his share of the net income of his Partnership. There is no assurance that the federal income tax rates discussed above will not be changed again in the future. We consent to the use of this letter as an exhibit to the Registration Statement, and all amendments to the Registration Statement, and to all references to this firm in the Prospectus. Very truly yours, /s/ Kunzman & Bollinger, Inc. KUNZMAN & BOLLINGER, INC. EX-10.(E) 4 ex10e.txt EXHIBIT 10(E) Exhibit 10(e) GAS PURCHASE AGREEMENT DATED MARCH 31, 1999 BETWEEN NORTHEAST OHIO GAS MARKETING, INC., AND ATLAS ENERGY GROUP, INC., ATLAS RESOURCES, INC., AND RESOURCE ENERGY, INC. GAS PURCHASE AGREEMENT ---------------------- This Agreement made and entered into as of this 31st day of March, 1999, by and between Northeast Ohio Gas Marketing, Inc., an Ohio corporation ("Buyer") of P.O. Box 430, Lancaster, Ohio 43130-0430 and Atlas Energy Group, Inc., an Ohio corporation, Atlas Resources, Inc., a Pennsylvania corporation and Resource Energy, Inc., a Delaware corporation (collectively "Seller"), of 311 Rouser Road, P.O. Box 611, Coraopolis, Pennsylvania 15108. RECITALS -------- WHEREAS, Buyer utilizes volumes of natural gas, hereinafter referred to as "gas", for its customers situated in Ohio and Pennsylvania; and WHEREAS, Seller is in the business of developing and producing a supply of gas from gas and/or oil wells situated in Ohio and Pennsylvania; and WHEREAS, Seller is the owner of such gas or is the authorized agent for the owner or owners of such gas and therefore has the authority to contract for the sale of such gas; and WHEREAS, Seller desires to sell and to agree to sell for itself and those owners for which it is the authorized agent, all of the gas produced from the wells, and Buyer desires to purchase such gas; and WHEREAS, as of the date hereof FirstEnergy Trading and Power Marketing, Inc. an affiliate of Buyer, and AIC, Inc., an affiliate of Seller, are entering into an agreement (the "Stock Purchase Agreement") relating to the purchase of all of the common stock of Atlas Gas Marketing, Inc. NOW, THEREFORE, in consideration of the mutual covenants contained herein and other good and valuable consideration, the receipt and sufficiency of which are hereby expressly acknowledged, the parties do hereby agree as follows: 1. AGREEMENT: Subject to the terms of this Agreement, Seller does hereby agree to sell to Buyer on a firm basis and Buyer does hereby agree to purchase on a firm basis, during the continuing term of this Agreement, those quantities of natural gas described in this Agreement. 2. TERM OF AGREEMENT: The term of this Agreement shall be effective for a primary term of ten (10) years commencing March 31, 1999 and terminating March 31, 2009. This Agreement shall automatically renew for successive annual terms unless either party, within one hundred twenty (120) days prior to the end of the primary term or any successive annual term, notifies the other party, in writing, of its intent to terminate this Agreement at the end of such term. The primary term and successive annual terms shall be considered the "term" of this Agreement. The price for gas for the first one (1) or two (2) years of the term of this Agreement shall be set forth on Schedule I attached hereto. The price for gas for subsequent annual periods shall be agreed to between Buyer and Seller by November 30th of each subsequent year for the next succeeding annual period, which period shall commence on April 1st. Should the Buyer and Seller be unable to reach agreement as to the purchase price, at any Point of Delivery, after the initial one or two year term, as applicable, or for any subsequent annual period, the Seller may solicit offers to purchase such gas from other third parties. In the event Seller should receive a bona fide offer to purchase all of Seller's gas, which is subject to this Agreement, at a specific Point of Delivery, it shall give notice (the "Notice") of the Point of Delivery, the name of prospective purchaser, the term of the proposed agreement and the purchase price to Buyer. If Buyer refuses to match such offer within five (5) business days of receipt of the Notice from Seller, then Seller shall be free to sell such gas to a party other than Buyer on the terms set forth in the Notice. Buyer's future rights to purchase such gas shall be restored at the completion of the term set forth in the Notice, subject to the provisions of this Paragraph. 3. DELIVERY POINT AND TRANSPORTATION: Subject to further provisions of this Agreement, and during the term hereof, any gas purchased hereunder shall be sold and delivered by Seller to Buyer at the interstate pipeline or local distribution company facilities of Tennessee Gas Pipeline Company, East Ohio Gas Company, National Fuel Gas Distribution, National Fuel Gas Supply, Peoples Natural Gas Company and Columbia Gas Transmission Corp., hereinafter be referred to as the "Points of Delivery". Additional Points of Delivery may be added by mutual agreement of Buyer and Seller. Title to the gas delivered hereunder shall vest to Buyer upon delivery by Seller to the Points of Delivery. Seller shall be responsible and pay for all gas transportation costs and retainage imposed by upstream pipelines to the Points of Delivery. As between the parties hereto, Seller shall be responsible for any damage or injury caused by the gas until the same shall have been delivered to the Points of Delivery after which delivery Buyer shall be in exclusive control and possession thereof and responsible for any damage or injury caused thereby. 4. QUANTITY: Seller shall exclusively make available to Buyer and Buyer agrees to purchase from Seller, during the term of this Agreement, a quantity equal to 100% of the current and future production into the Points of Delivery. Except as otherwise provided in this Section, Seller shall deliver all gas it develops and produces into the Points of Delivery. Unless agreed to by Buyer, Seller shall not sell any gas to any other party. It is currently estimated that Atlas Energy Group, Inc. and Atlas Resources, Inc. will collectively deliver approximately 27,000 Mcf per day and Resource Energy, Inc. will deliver approximately 7,000 Mcf per day at the Points of Delivery. Buyer and Seller agree 2 to mutually cooperate and regularly meet to establish production schedules of gas into the Points of Delivery. Seller shall nominate, by the 25th calendar day of the preceding month, the daily volumes to be delivered during the following month to the Points of Delivery. Seller's daily deliveries shall be no greater than one hundred and ten percent (110%) or no less than ninety percent (90%) of Seller's daily nominated volumes, as long as Seller's deliveries at each Point of Delivery are at least 500 Mcf per day, with the exception of the Wheatland Dehydration Meter, for which the minimum volume is 300 Mcf per day. If Seller's daily volume delivery is less than ninety percent (90%) of Seller's daily nominated volume, then Seller shall pay Buyer one hundred and two percent (102%) of the Buyer's replacement cost, less the price set forth on Schedule I, for the volume of gas which is the difference between Seller's daily volume delivery and ninety percent (90%) of Seller's daily nominated volume. If Seller's daily volume delivery is more than one hundred and ten percent (110%) of Seller's daily nominated volume, then, regardless of other pricing provisions contained in this Agreement, Buyer shall pay Seller ninety eight percent (98%) of the daily market price for each Point of Delivery, as set forth on Schedule I, for the volume of gas which is the difference between Seller's daily volume delivery and one hundred and ten percent (110%) of Seller's daily nominated volume. Notwithstanding the first paragraph of this Section 4, it is understood and agreed to by the parties that Seller shall continue to supply gas to its three (3) direct delivery customers, Wheatland Tube Company, CSC Industries and Warren Consolidated for the life of those agreements, including any extensions or renewals. Buyer and Seller agree that Buyer will provide all billing services for the above three (3) customers. Buyer agrees that it will not utilize Seller's local production, or any other source of supply, as source of sales to the above three (3) customers of Seller to the extent Buyer's offer would supplant or in any manner displace the existing amount of Seller's direct delivery arrangements through the term of Seller's agreements with the above three (3) customers, including any extensions or renewals. Seller currently delivers 2,600 Mcf per day to the Wheatland Tube Company, 3,400 Mcf per day to CSC Industries and 325 Mcf per day to Warren Consolidated. Seller agrees that Buyer may sell any amount, in excess of Seller's current volumes (so long as Seller continues to have a contact with the above three (3) customers) to such customers. Buyer shall not be restricted in selling to any of the above three (3) customers if Seller no longer has a contract with such customer. Seller's commitment to deliver all of the gas it produces to Buyer is subject to the right of investors, including limited partnerships where Seller is acting as the General Partner, in wells operated by Seller, to take their gas in kind. In the event a party wishes to take its gas in kind, Seller shall promptly notify Buyer. Seller further agrees to indemnify Buyer for all losses attributable to gas which has been taken in kind by investors in wells operated by Seller, to the extent Buyer has incurred a loss on such gas because of a prior commitment by Buyer. 3 5. PURCHASE PRICE: The price to be paid by Buyer to Seller for gas delivered to Buyer at the Point(s) of Delivery shall be as set forth on Schedule I attached hereto. 6. BILLING AND PAYMENT: Invoices shall be rendered to Buyer by the 14th calendar day of the month for gas delivered the preceding monthly period and payment shall be made monthly to Seller not later than the 28th calendar day of the month. Payment shall be made at the following address, or other address that may be designated by Seller from time to time: 311 Rouser Road, P.O. Box 611, Coraopolis, Pennsylvania 15108. Invoices shall be delivered to Buyer at: P.O. Box 430, Lancaster, Ohio 43130-0430. The quantities invoiced by Seller will be based on the quantities delivered by Seller at the Point(s) of Delivery. In the event the actual quantity delivered to the Point(s) of Delivery is unavailable, the estimated volumes of gas tendered for delivery by Seller to the Point(s) of Delivery shall be invoiced to Buyer. Any appropriate adjustment shall be made in the following billing period. Payment not received by the twenty-eighth (28th) calendar day of the month shall bear interest at PNC Bank, NA's then current prime lending rate minus two percent (2%). 7. QUALITY AND MEASUREMENT: Seller warrants that gas delivered under this Agreement shall meet the quality and measurement standards established by interstate pipeline and/or local distribution companies receiving gas from Seller for Buyer's account at the Point(s) of Delivery. 8. WARRANTY OF TITLE AND TAXES: Seller warrants title to all gas delivered by it and warrants that such gas is free from all liens and adverse claims. Seller shall indemnify and save Buyer harmless against all suits, debts, damages, costs and expenses arising from adverse claims to the gas delivered by it or taxes, payments or other charges thereon applicable before such gas is delivered to the Point(s) of Delivery. All present and future production, severance, gross proceeds or assessments of a similar nature imposed or levied by any state or other governmental agency or duly constituted authority upon the gas sold and delivered hereunder and the components thereof and the royalty, overriding royalty, production payment and other lease burden owners, as the case may be, shall be borne and paid by Seller. In the event Buyer is required to pay any of such taxes and assessments, Buyer may deduct same from the payments to be made by it hereunder and may make a reasonable charge for such service. Buyer shall be responsible for all taxes, liens and adverse claims, which may be imposed on such gas after the Point(s) of Delivery. 9. REGULATORY BODIES: This Agreement and Buyer's and Seller's obligation hereunder shall be subject to all valid applicable State and Federal laws, and orders, directives, rules and regulations of any government body or official having jurisdiction hereunder. 10. NOTICES: Whenever under the terms of this Agreement, any notice is required or permitted to be given by one party to the other, it shall be given in writing and shall be deemed to have been sufficiently given for all purposes hereof if sent by telegram or mailed, postage prepaid, to the parties at the addresses set forth below: 4 Seller: Atlas Energy Group, Inc. Atlas Resources, Inc. Resource Energy, Inc. Attn: Contract Administrator 311 Rouser Road P.O. Box 611 Coraopolis, Pennsylvania 15108 Buyer: Northeast Ohio Gas Marketing, Inc. Attn: Contract Administrator P.O. Box 430 Lancaster, Ohio 43130-0430 11. GOVERNING LAW: The interpretation and performance of this Agreement shall be in accordance with the laws of the State of Ohio. 12. FORCE MAJEURE: If either Buyer or Seller is rendered unable, wholly or in part, by force majeure to perform its obligations under this Agreement, other than the obligation to make payments then or thereafter due, it is agreed that performance of the respective obligations of the parties hereto to deliver and receive gas, so far as they are affected by such force majeure, shall be suspended from the inception of any such inability until it is corrected, but for no longer period. The party claiming such inability shall give notice thereof to the other party as soon as practicable after the occurrence of the force majeure. If such notice is first given by telephone communications, it shall be confirmed promptly in writing giving full particulars. The party claiming such inability shall promptly correct such inability to the extent it may be corrected through the exercise of reasonable diligence. Force majeure as used herein shall mean acts of God, vandalism, war, civil disturbance, rebellion, blockade, strike or other labor dispute, lightning, fire, flood, explosion, hurricane, freezing of wells or pipelines which result in the failure of third party pipelines to transport gas hereunder, permanent plant closing of either the Carbide Graphite plant or the Duferco Farrell Corporation plant (during the term of the existing agreement with such party, excluding any extensions or renewals) and other causes not within the control of the party claiming a force majeure situation. 13. ASSIGNMENT: Neither party may assign any of its rights under this Agreement without the prior written consent of the other party, which will not be unnecessarily withheld, except that Buyer may assign any of its rights under this Agreement to any affiliate of Buyer, provided that Buyer remains responsible for all financial obligations hereunder. Subject to the preceding sentence, this Agreement will apply to, be binding in all respects upon, and inure to the benefit of the successors and permitted assigns of the parties. 14. SURVIVAL OBLIGATIONS: The obligation of Buyer to make payment hereunder shall survive the termination or cancellation of this Agreement. The obligations of Seller to indemnify Buyer pursuant to the provisions set forth under Section 8 shall survive the termination or cancellation of this Agreement. If any provision in this 5 Agreement is determined to be invalid, void, or made unenforceable by any court having jurisdiction, then such determination shall not invalidate, void or make unenforceable any other provision, agreement or covenant in this Agreement. No waiver of any breach of this Agreement shall be held to be a waiver of any other or subsequent breach. All remedies afforded in this Agreement shall be taken and construed as cumulative, that is, in addition to every other remedy provided therein or by law. 15. COMPLETE AGREEMENT: This Agreement, and the Stock Purchase Agreement, represent the complete and entire understanding between the parties and their affiliates respecting the subject matter of this transaction. The parties hereto declare that there are no promises, representations, conditions, warranties or other agreements, express or implied, oral or written, made or relied upon by either party, except those contained herein or in the Stock Purchase Agreement. 6 IN WITNESS WHEREOF, the parties, or their authorized agent, hereto have caused this Agreement to be executed on this the 31 day of March, 1999. Witnesses: Seller: Atlas Energy Group, Inc. By: JR O'MARA - ------------------------------------ --------------------------------- Title: PRESIDENT - ------------------------------------ ------------------------------ Witnesses: Seller: Atlas Resources, Inc. By: JR O'MARA - ------------------------------------ --------------------------------- Title: PRESIDENT - ------------------------------------ ------------------------------ Witnesses: Seller: Resource Energy, Inc. By: N.J McGurk - ------------------------------------ --------------------------------- Title: V.P. - ------------------------------------ ------------------------------ Witnesses: Buyer: Northeast Ohio Gas Marketing, Inc. By: - ------------------------------------ --------------------------------- Title: - ------------------------------------ ------------------------------ IN WITNESS WHEREOF, the parties, or their authorized agent, hereto have caused this Agreement to be executed on this the 31 day of March, 1999. Witnesses: Seller: Atlas Energy Group, Inc. By: - ------------------------------------ --------------------------------- Title: - ------------------------------------ ------------------------------ Witnesses: Seller: Atlas Resources, Inc. By: - ------------------------------------ --------------------------------- Title: - ------------------------------------ ------------------------------ Witnesses: Seller: Resource Energy, Inc. By: - ------------------------------------ --------------------------------- Title: - ------------------------------------ ------------------------------ Witnesses: Buyer: Northeast Ohio Gas Marketing, Inc. By: Dean K Cobbs - ------------------------------------ --------------------------------- Title: VICE PRESIDENT - ------------------------------------ ------------------------------ 7 Schedule I Purchase Price For Natural Gas From Atlas Affiliated Production Companies
Point of Delivery Estimated Initial of Equity Gas Price Supply Term ------------- ----- ------ ---- East Ohio Gas CNG South (Gas Daily/FOM) + 1,550 Mcf/Day 4/1/99 to $0.235/Mcf 3/31/01 National Fuel Gas Distribution TCO (Inside FERC/FOM Appl. 400 Mcf/Day 4/l/99 to Index) + $0.175/Mcf 3/31/01 National Fuel Gas Supply 100% TCO (Inside FERC/FOM 14,000 Mcf/Day 4/l/99 to Appl. Index)/Dth 3/31/00 Peoples Natural Gas CNG South (Gas Daily/FOM) + 1,300 Mcf/Day 4/1/99 to $0.140/Mcf 3/31/01 Columbia Gas Transmission 99% TCO (Inside FERC/FOM 100 Mcf/Day 4/l/99 to Appl. Index)/Dth 3/31/01 Tennessee Gas Pipeline-Zone 4 CNG North (Gas Daily/FOM) - 6,900 Mcf/Day 4/l/99 to $0.105/Dth 3/31/00
Prices set forth above presume that Seller will incur any applicable financial losses involving equity volumes as the result of previous financial transactions (e.g., NYMEX and financial basis transactions). The purchase price and estimated supply of natural gas provided by Resource Energy, Inc., as set forth on Schedule II, will be negotiated between Buyer and Seller as existing Resource Energy, Inc. contracts terminate. All renegotiated contracts between Buyer and Seller will have a common termination date of March 31st. The list of contracts set forth on Schedule II shall be modified as each contract is renegotiated. 8 Schedule II RESOURCE ENERGY, INC. GAS SALES AGREEMENTS As of 3/1/99
- ------------------------------------------------------------------------------------------------------------------------------------ Current Approx. Contract Pipeline Original Expirations Monthly No. System Wells and/or Stations Purchaser Contract (including Volume --- ------ --------------------- --------- -------- Amendments) ------ - ------------------------------------------------------------------------------------------------------------------------------------ GS-001 TUSC-HARRISON BRAINERD 5394 EAST OHIO GAS 12/31/69 LIFE OF WELL 6,000 GS-015 TUSC-HARRISON WASH-FREEPORT G509 EAST OHIO GAS 11/18/85 ANNUAL 9,000 TUSC-HARRISON TUSC. D J880 EAST OHIO GAS N/A LIFE OF WELL 2,700 GS-034 BU MEDINA CITY GATE 714873 (COH) VOLUNTEER 11/01/94 11/01/99 4,500 ENERGY GS-044 BUTLER SALEM CITY GATE 744096 (COH) INTERSTATE GAS 10/01/94 10/01/99 11,000 SUPPLY FISH NEWCOMERSTOWN 744588 (COH) INTERSTATE GAS 10/01/99 4,800 SUPPLY GS-050 BU BU EAST A635(EOG) HARRISON 01/24/95 MONTHLY 2,000 ENERGY (WINTER) GS-051 TUSC-HARRISON TUSC. D WELLS J273 PIEDMONT GAS 01/26/95 01/26/00 1,000 Co. (WINTER) GS-033 TUSC.-HARR; TUSC. D; BARRS MILLS J273; BB01P PIEDMONT GAS 10/08/91 MONTHLY BB01P Co. GS-052 TUSC.-HARRISON EOG STATIONS 444,J273,K018 VOLUNTEER 04/01/95 10/01/99 40,000 ENERGY WEST-HANOVER C277 & H474 VOLUNTEER ENERGY MEDINA SUMMIT A635, A750, et al. VOLUNTEER ENERGY LIBERTY A451 VOLUNTEER ENERGY KIBLER K962 VOLUNTEER ENERGY GS-012 WEST-HANOVER 6 WELLS D399 EAST OHIO GAS 01/22/85 LIFE OF WELL 1,000 GS-016, 017 WEST-HANOVER 8 WELLS G511, G684 EAST OHIO GAS 3/5/86, 11/21/85 LIFE OF WELL 1,750 GS-020, WEST-HANOVER 11 WELLS J826 EAST OHIO GAS 5/6/87,5/27/87 LIFE OF WELL 2,400 021,023 GS-014 SANOR(EOG) L. SANOR #1 G347 EAST OHIO GAS 09/30/85 LIFE OF WELL 250 GS-108 NEW YORK NORTH HARMONY 632207 (CGTC) VOLUNTEER 01/01/97 Monthly with ENERGY Trigger option GS-109 NEW YORK NORTH HARMONY GOOSE CREEK 03/01/96 12/31/99 1,000-8,000 DRILLING GS-501 SPRING CREEK, SPRING CREEK 621403 (CGTC) COLUMBIA 12/01/96 Monthly with 7,000 PA ENERGY Trigger option SERVICES GS-502 SPRING CREEK, FLICK. JOHNSON via Belden & Blake BELDEN & BLAKE 07/14/89 MONTHLY 300 (NFG) MB-SUGAR SUGAR AMI MB OPERATING 01/13/98 03/15/00 45,000 CREEK (via Volunteer Energy) GS-181 THOMPSETT REI-NY 621189 (CGTC) RILEY NATURAL 02/01/98 Monthly with 20,000 GAS Trigger option OAG 621929 (CGTC) AREA #1 622657 (CGTC) Belden & Blake as 11/98 GS-182 THOMPSETT GERRY HOMES #1 & #2 GERRY NURSING 01/25/93 01/25/99 500 HOMES WOLCOTT WOLCOTT 9 WELLS LENAPE N/A 05/30/99 2,000 RESOURCES GS-180 DOVER ROSO2P (EOG J094 available) ARMCO, INC. 11/01/87 06/30/99 11,000 GS-175 GEER STEEL 11/01/88 11/30/99 GS-177 UNION COUNTRY 04/30/92 04/30/02 CLUB GS-152 BB01P BB01P BELDEN BRICK 01/23/84 12/31/96 CO. GS-150 GARAWAY 09/24/89 09/24/01 4,000 SCHOOLS NEW BB01P 5196 (EOG) KOHR VOLUNTEER 11/09/98 12/15/99 3,500 ENERGY FISH J700,A294,J436,H794, J163, K794 VOLUNTEER 11/09/98 12/15/99 2,250
ENERGY DOVER J094 VOLUNTEER 11/09/98 12/15/99 0 ENERGY GS-178 ELLIOTT 5503 J514, H556 NGO 02/15/94 MONTHLY 2,300 GS-178 WILKIN, ARTH, SRO1P NGO 10/01/92 MONTHLY 900 ROBINSON GS-178 BUCKEYE ROS01WL WEST LAFAYETTE NGO 11125/92 MONTHLY 5,500 STREET GS-155 EGGLESTON et al. G547 EAST OHIO GAS 08/15/85 LIFE OF WELL 1,250 GS-176 ROBERTS DURINKA H551, H509 JDS 10/01/98 11/15/99 600 GS-156 ADDY, et al. H383 EAST OHIO GAS 03/04/87 LIFE OF WELL 2,750 GS-174 ROFF J.ROFF #1 727392 (CGTC) INTERSTATE GAS 04/29/96 09/01/99 100 SUPPLY WILLS WILLS SYSTEM 721423 (CGTC) INTERSTATE GAS 1,400 SUPPLY DIORIO ELMO DIORO ELMO #2 719240 (CGTC) INTERSTATE GAS 100 SUPPLY GS-154 GLOD GLOD #1 & #2 ATLAS ENERGY 10/14/84 LIFE OF WELL 250 GS-161 MISC. EOG SHOEBRUNN #1, #2 J018 EAST OHIO GAS 04/28/88 LIFE OF WELL 350 CONTRACTS GS-163 (DAC AIRPORT #1 & #2 H486 EAST OHIO GAS 04/10/87 LIFE OF WELL 500 AQUISITION) GS-166 CLINE-TUSC. #1 G746 EAST OHIO GAS 02/28/86 LIFE OF WELL 450 GS-167 DURDEN, WHERELY D303 EAST OHIO GAS 12/17/84 LIFE OF WELL 950 GS-168 R. SPRING #1 6589 EAST OHIO GAS 09/01/97 LIFE OF WELL 0 GS-169, 170 SIEGENTHALER #1 & #2 J027 EAST OHIO GAS 04/28/88 LIFE OF WELL 300 GS-171, 172 GALBRAITH #1, CONANT #1 EAST OHIO GAS 06/13/88 BONANZA HADDORN, SILER, FRACE, KORN, MB OPERATING 01/23/76 LIFE OF WELL 500 YARGER LIBSON KLEMMAN #1 BELDEN & BLAKE 01/14/97 10/31/99 450 - ------------------------------------------------------------------------------------------------------------------------------------
10 AMENDMENT TO GAS PURCHASE AGREEMENT ----------------------------------- THIS AMENDMENT, dated as of February 1, 2001, by and between Atlas Resources Inc., a Pennsylvania corporation, Atlas Energy Group, Inc., an Ohio corporation, and Resource Energy, Inc., a Delaware corporation (hereinafter collectively referred to as "Seller"), and FirstEnergy Services Corp., an assign of Northeast Ohio Gas Marketing, Inc. ("Buyer"); WHEREAS, Buyer and Seller are parties to an Agreement dated March 31, 1999 (the "Agreement"), concerning the sale and purchase of natural gas; and WHEREAS, Viking Resources Corporation ("Viking"), is in the business of developing and producing natural gas from wells in Ohio and Pennsylvania, and recently became an affiliate of Seller; and WHEREAS, Viking is the owner of such natural gas or is the authorized agent for the owner of such natural gas and therefore has the authority to contract for the sale of such natural gas; and WHEREAS, as an inducement for Buyer to establish a Guaranty to Seller from Buyer's parent, FirstEnergy Corp., Viking has offered to sell for itself and those owners for which it is the authorized agent all of the gas produced at the meters identified on Exhibit A attached hereto, and Buyer offered to purchase such natural gas from Viking; NOW, THEREFORE, in consideration of the mutual covenants contained herein, and other good and valuable consideration, the Seller and Buyer do hereby agree to amend the Agreement to include the purchase and sale of Viking's natural gas production at the meters identified on Exhibit A. This Amendment shall become effective upon execution by the parties. All other terms and conditions of the Agreement shall remain in full force and effect. IN WITNESS WHEREOF, the parties have hereunto set their corporate signatures by their duly authorized officers as of the day and year first above written. WITNESS: SELLERS: ATLAS RESOURCES, INC. ATLAS ENERGY GROUP, INC. RESOURCE ENERGY, INC. VIKING RESOURCES CORPORATION Michael G. Hartzell Frank P. Carolas - --------------------------------- ---------------------------- By: Frank P. Carolas Executive Vice-President WITNESS: BUYER: FIRSTENERGY SERVICES CORP. Karen Johnson Michael A. Senss - --------------------------------- ---------------------------- By: EXHIBIT A attached to and made part of the Amendment dated February 1, 2001 between Atlas Resources, Inc., et. al. (Seller) and FirstEnergy Services Corp. (Buyer) Pipeline or LDC Station # Identification TETCO 73133 FAYETTE COUNTY, PA EOG 3545 COOK EOG 3622 REYNOLDS EOG 3695 HOFFMAN MARY L #1 EOG 3711 HOFFMAN MARY L #2 EOG 3727 MOULTON EOG 5498 CUMMINS #3 EOG 5993 KARAS P W #9 EOG 6056 WELLING UN #1 EOG 6350 DEMOSS UNIT #1 EOG 6445 LEE T #1 EOG A498 FAGERT #1 EOG A501 HAIMERL-LOPEZ #2 EOG A632 HENRY R #1 EOG B046 THOMAS #11 EOG B049 VIKING - TCO EOG B088 WALTERS #1 EOG B172 STEPANICK UN #10 EOG B203 KLYN #1 EOG B222 GRAF-GROWERS EOG B330 FRAME #1 EOG B334 ALESSIO #1 EOG B355 HORAK #1 EOG C134 SANDSTROM #1 EOG C161 MORA-HUTINGER #2 EOG C381 GRAF GROWERS #3 EOG C598 HILL 2 EOG C818 BROWN W #1 EOG C826 BOLTZ UNIT #1 EOG D262 JAITE #3 EOG D361 ADVEY JOLES #1 EOG D412 STEPHENS #4 EOG D572 STACHOWSKI EOG D598 GRECH 4 EOG D732 PADULA KANE #2 EOG E101 KRUG #1 EOG E122 SNYDER E I #1 EOG E158 WHITEHOUSE FRUIT FARM EOG E218 TOALSTON #1 EOG E222 BARNETT #2 Page 1 of 3 EXHIBIT A attached to and made part of the Amendment dated February 1, 2001 between Atlas Resources, Inc., et. al. (Seller) and FirstEnergy Services Corp. (Buyer) EOG E334 GREENLEAF / WYMER #1 EOG E336 KIKO #3 EOG E347 CRANE #2 KW EOG E358 CITY OF ALLIANCE EOG E376 HARVEY UNIT #1 EOG E378 KARAS #19 EOG E379 HAISS #2 EOG E384 WOODS #1 EOG E387 BAIN #2D EOG E416 SHINN #2D EOG E417 BANDY #1D EOG E518 VENCE HAISS #1 EOG E520 TACKAS #1 EOG E522 TOMPULIS #2 EOG E598 WEBER UNIT #1 EOG G198 DZURO-KOVACS #1 EOG G348 WILLOUGHBY SYSLO #1 EOG G485 POPADICH #2 EOG G516 MATHEOS #2 EOG G563 PAGERT H UN #3 EOG G564 PUGH C UN #3 EOG G589 FROST J UN #2 EOG G658 WALTERS UNIT #2 EOG G673 MCGEE U #2 EOG G692 BETTIS UN #1 EOG H062 BAKER F #1 EOG H159 FROST JB & AF #1 EOG H193 DUBETZ UN #1 EOG H216 WELLING UNIT #2 EOG H236 SWIGER EOG H244 MATHEOS 3 EOG H252 JOHNSON UNIT #1 EOG H285 USA MCKIBBEN #2 EOG H354 CITY OF ALIANCE 1 EOG H517 KAUFMAN #2 EOG H518 WAYSIDE #1 EOG H546 STACHOWSKI #2 EOG H690 BUCARION UNIT #1 EOG H823 USA / MCKIBBEN UNIT #4 EOG J208 VANMATTER-CUNNINGHAM #2 EOG J212 REBOLD UNIT #1 EOG J213 SCHISLER / USA UNIT #1 EOG J214 BUCARION UNIT #2 EOG J249 AMERITRUST Page 2 of 3 EXHIBIT A attached to and made part of the Amendment dated February 1, 2001 between Atlas Resources, Inc., et. al. (Seller) and FirstEnergy Services Corp. (Buyer) EOG J609 KARAS P W #1 EOG J801 CRUTCHLEY POOL UNIT #1 EOG K024 SCHWARK #2 EOG K111 CITY OF ALIANCE #9 EOG K157 BERLIN RESERVOIR #6D EOG K169 KARAS #18 EOG K170 ELLSWORTH UNIT #3 EOG K171 HENRY #2 EOG K173 SCHMEIDLIN UNIT #1 EOG K246 BERLIN RESERVOIR #21D EOG K252 WALLBROWN #10 EOG K265 MILLER L #2 EOG K306 BERLIN RESERVOIR #18D EOG K315 BERLIN RESERVOIR #22D EOG K396 DVORACEK #1 EOG K401 MATHEWS C J UNIT #1 EOG K429 WALLBROWN #9 EOG K430 BERLIN RESERVOIR #34D EOG K439 MUEHLEINSEN #1 EOG K455 REPICH J & M #2 EOG K458 VIKING - TCO EOG K472 MORRIS P UNIT #2 EOG K530 BERLIN RESERVOIR #31 EOG K542 BERLIN RESERVOIR #35 EOG K544 BERLIN RESERVOIR #2D EOG K599 MICHAEL #2 EOG K660 MWCD #7 EOG K663 CARLISLE UNIT #1 EOG K677 SMITH / STANLEY #1 EOG K718 MWCD #1 EOG K832 BOWLING #1 EOG K833 AHART #1 EOG K909 HORNFECK #1 EOG K934 BEAVER LAND #2 EOG K938 BENNER #1 EOG K939 HUDGENS #1 EOG K960 BIEBER UNIT #1 EOG R037 SPECHT #1 EOG R038 THAYER UNIT #1 EOG R044 STRONG #1 EOG R050 MIKES-MILLER #1 EOG R124 THOMAS #2 EOG R537 ADAMS D&M #1 EOG R538 LANG F #1 Page 3 of 3 ATTACHMENT 1 NFGS Measuring Station Description PSP1130031 AMMANN PSP1129541 BOONE MOUNTAIN PSP1128771 JACKSON CENTER, NFGS PSP1128681 GARVIS STATION PSP1127341 HURTT CS PL00000015 NM POOL 623906 Little Valley 617733 Sugar Grove ATTACHMENT 2 Page 1 EOG Measuring Station Description 3545 COOK 3622 REYNOLDS 3695 HOFFMAN MARY L #1 3711 HOFFMAN MARY L #2 3727 MOULTON 5196 KOHR STATION 5498 CUMMINS #3 5993 KARAS P W #9 6056 WELLING UN #1 6350 DEMOSS UNIT #1 6445 LEE T #1 A294 LITTLE UNIT #1 A444 Harshey Station A451 Weber #4 A498 FAGERT #1 A501 HAIMERL-LOPEZ #2 A532 Davies L & B A632 HENRY R #1 A635 Betts #1 A750 Fabro #1 B046 THOMAS #11 B049 VIKING - TCO B088 WALTERS #1 B141 SOVARY BURKHART #1 B172 STEPANICK UN #10 B203 KLYN #1 B222 GRAF-GROWERS B273 HOLLERAN UNIT #1 B297 VAN HYNING R #4 B299 VAN HYNING H #1 B330 FRAME #1 B334 ALESSIO #1 B355 HORAK #1 B412 Musser #2 C010 Steiner #1 C134 SANDSTROM #1 C161 MORA-HUTINGER #2 C277 CURFMAN #1 C381 GRAF GROWERS #3 C390 BUTCHER #1 C407 EVERETT #2 C472 REAM V ET AL #1 C473 Lemon Unit #1 C598 HILL 2 C787 Butcher F #4 C804 PETRICK #1 C811 Wilhite #2 ATTACHMENT 2 Page 2 EOG Measuring Station Description C818 BROWN W #1 C821 Farris #1 C826 BOLTZ UNIT #1 C855 MIDDLETON BANK #2 D018 PEMBERTON UNIT #1 D140 PETRICK #2 D202 D J & J #1 D256 BELAK #2 D262 JAITE #3 D337 SAPP UNIT #1 D361 ADVEY JOLES #1 D412 STEPHENS #4 D424 RYDECK #1 D481 Jones-Blane D572 STACHOWSKI D598 GRECH 4 D610 Berry Charles A. Unit #1 D732 PADULA KANE #2 D810 L & W Associates #1 E101 KRUG #1 E122 SNYDER E I #1 E158 WHITEHOUSE FRUIT FARM E218 TOALSTON #1 E222 BARNETT #2 E334 GREENLEAF / WYMER #1 E336 KIKO #3 E347 CRANE #2 KW E358 CITY OF ALLIANCE E376 HARVEY UNIT #1 E377 BEAL #1 E378 KARAS #19 E379 HAISS #2 E384 WOODS #1 E387 BAIN #2D E416 SHINN #2D E417 BANDY #1D E518 VENCE HAISS #1 E520 TACKAS #1 E522 TOMPULIS #2 E598 WEBER UNIT #1 E935 MATTMARK WELLS E937 AEP 9-6 E939 AEP WELLS E950 AEP WELLS G198 DZURO-KOVACS #1 G348 WILLOUGHBY SYSLO #1 G485 POPADICH #2 ATTACHMENT 2 Page 3 EOG Measuring Station Description G509 OLD LOW G516 MATHEOS #2 G563 PAGERT H UN #3 G564 PUGH C UN #3 G589 FROST J UN #2 G658 WALTERS UNIT #2 G673 MCGEE U #2 G692 BETTIS UN #1 G712 FISHER #1 H127 MONUS #3 H159 FROST JB & AF #1 H193 DUBETZ UN #1 H216 WELLING UNIT #2 H236 SWIGER H244 MATHEOS 3 H252 JOHNSON UNIT #1 H260 Lermer #2 H285 USA MCKIBBEN #2 H354 CITY OF ALIANCE 1 H474 Smith, Elize #2 H518 WAYSIDE #1 H546 STACHOWSKI #2 H690 BUCARION UNIT #1 H794 Casteel Robert #2 H823 USA / MCKIBBEN UNIT #4 H882 GAFFNEY UNIT #1 J094 Winkler #5 J163 Peters ET AL #1 J180 KING #1 J208 VANMATTER-CUNNINGHAM #2 J212 REBOLD UNIT #1 J213 SCHISLER / USA UNIT #1 J214 BUCARION UNIT #2 J249 AMERITRUST J273 LINT #1 J436 ROSS #2 J609 KARAS P W #1 J700 Smith Unit #5 J801 CRUTCHLEY POOL UNIT #1 K018 SHUSS #8 K024 SCHWARK #2 K111 CITY OF ALIANCE #9 K157 BERLIN RESERVOIR #6D K169 KARAS #18 K170 ELLSWORTH UNIT #3 K171 HENRY #2 K173 SCHMEIDLIN UNIT #1 ATTACHMENT 2 Page 4 EOG Measuring Station Description K204 KNICKERBOCKER #1 K246 BERLIN RESERVOIR #21D K252 WALLBROWN #10 K265 MILLER L #2 K306 BERLIN RESERVOIR #18D K315 BERLIN RESERVOIR #22D K396 DVORACEK #1 K401 MATHEWS C J UNIT #1 K429 WALLBROWN #9 K430 BERLIN RESERVOIR #34D K439 MUEHLEINSEN #1 K455 REPICH J & M #2 K458 VIKING - TCO K472 MORRIS P UNIT #2 K530 BERLIN RESERVOIR #31 K542 BERLIN RESERVOIR #35 K544 BERLIN RESERVOIR #2D K599 MICHAEL #2 K660 MWCD #7 K663 CARLISLE UNIT #1 K677 SMITH / STANLEY #1 K718 MWCD #1 K758 HUBBARD STATION K794 Miller-Addy #1 K832 BOWLING #1 K833 AHART #1 K909 HORNFECK #1 K934 BEAVER LAND #2 K938 BENNER #1 K939 HUDGENS #1 K960 BIEBER UNIT #1 K962 Kihler #1 R037 SPECHT #1 R038 THAYER UNIT #1 R044 STRONG #1 R050 MIKES-MILLER #1 R065 CARVER #1 R066 SAPP UNIT #2 R107 ERNEST #2 R124 THOMAS #2 R141 EVERETT #1 R261 FOLK #1 R537 ADAMS D&M #1 R538 LANG F #1 [GRAPHIC OMITTED] ATTACHMENT 3 PNG Measuring Station Description 8192 FELIX #1 8218 COULTER 9275 GROVE CITY MALL 9346 FELIX #2 9518 CARUSO 9627 PNG WEST / EWIG ATTACHMENT 4 TCO Measuring Station Description 718439 Lordstown-Adam 718626 Lordstown-Koch 720294 Newton Falls ATTACHMENT 5 NFGD Measuring Station Description PDP1127411 WHEATLAND DEHY PDP1222781 SCHUSTER PDP1226731 SHIPTON EX-10.(F) 5 ex10f.txt EXHIBIT 10(F) Exhibit 10(f) GUARANTY DATED AUGUST 12, 2003 BETWEEN FIRST ENERGY CORP. AND ATLAS RESOURCES, INC. TO GAS PURCHASE AGREEMENT DATED MARCH 31, 1999 BETWEEN NORTHEAST OHIO GAS MARKETING, INC., AND ATLAS ENERGY GROUP, INC., ATLAS RESOURCES, INC., AND RESOURCE ENERGY, INC. FirstEnergy(R) 76 South Main St. Akron, Ohio 44308 - -------------------------------------------------------------------------------- 1-800-633-4766 Guaranty dated as of August 12, 2003 by and between FirstEnergy Corp., an Ohio corporation, with its principal place of business at 76 South Main Street, Akron, OH 44308 ("Guarantor") and Atlas Resources Inc., a Pennsylvania corporation, with its principal place of business at 311 Rouser Rd., Coraopolis, PA 15108 ("Seller"). Seller, together with its affiliates Atlas Energy Group, Inc., an Ohio Corporation, Resource Energy, Inc., a Delaware corporation, and Viking Resources Corporation, an Ohio Corporation, entered into a Gas Purchase Agreement for the purchase and sale of natural gas ("Sales Agreement") to FirstEnergy Solutions Corp.,("Customer"), a subsidiary of the Guarantor. In consideration thereof, and as an inducement for the extension of credit by the Seller to the Customer, the Guarantor hereby absolutely and unconditionally guarantees to the Seller, its permitted successors and assigns pursuant to this letter (this "Guaranty"), the prompt payment (within three (3) business days of demand by the Seller) of any and all amounts that are or may hereafter become due and payable (taking into account all applicable grace periods) from the Customer to the Seller by reason of the Sales Agreement (the "Obligations"), to fully perform the Sales Agreement, as well as any indebtedness under the Sales Agreement (regardless of whether such indebtedness be in the form of book accounts, promissory notes, trade acceptances, checks, drafts, or other evidence of indebtedness, together with late fees, service charges or liquidated damages (but only if, and to the extent, provided for in the Sales Agreement) and interest at the rate specified therein) This Guaranty shall be a guaranty of payment, and not of collection, and the Seller shall not be required to take any proceedings or exhaust its remedies against the Customer prior to the exercise of its rights and remedies against the Guarantor, as guarantor. The Guarantor hereby agrees to reimburse the Seller for all sums paid to it by the Customer under the Sales Agreement, which must subsequently be returned by the Seller to the Customer as a preference or fraudulent transfer under the Federal Bankruptcy Code, any applicable state law and for any other reason. Notwithstanding anything else in this Guaranty to the contrary, the obligation and liability of Guarantor hereunder shall not (i) be effective or enforceable with respect to any Obligation, liability or claim relating in any way to consequential, indirect, punitive or exemplary damages of any kind whatsoever, whether owing by Company or otherwise, and (ii) exceed Fifteen Million Dollars ($15,000,000) in the aggregate. This Guaranty is a continuing guaranty and shall remain in full force and effect from August 12, 2002 until at least March 31, 2005, and shall continue on a monthly basis thereafter, unless terminated by either party with thirty (30) days written notice to the other party. If the Guarantor shall be adjudicated bankrupt under the Federal Bankruptcy Laws, or if any petition for any relief under any of such laws shall be filed by or against the Guarantor, or if the Guarantor shall make an assignment for the benefit of creditors or shall apply for a receiver for all or any part of its property, or if the Guarantor shall become insolvent or unable to pay its debts as they mature, then and in any such event all of the Obligations shall forthwith become and be immediately due and payable by the Guarantor. Notice of demand by the Seller shall be sent by either certified mail, return receipt requested, or hand delivery, to the respective addresses specified above, with notices to the Guarantor sent to the attention of the Credit Manager and notices to the Seller sent to the attention of both John Ranieri and Nancy McGurk, and shall be deemed to be received on the day that such writing is delivered to the intended recipient thereof. 1 The Guarantor hereby acknowledges that any modification of the Sales Agreement shall not affect the liability of the Guarantor with respect hereto. Except as provided above with respect to the requirement of notice from the Seller to the Guarantor of a payment demand, the Guarantor hereby waives, to the extent permitted by law, the requirements of the giving of any notice, including, but not limited to, (a) notice of the acceptance of this Guaranty by the Seller; (b) notice of the entry into the Sales Agreements between the Customer and the Seller and of any modifications thereto; (c) notice of any extension of time for the payment of any sums due and payable to the Seller under the Sales Agreement; (d) with respect to any notes or evidence of indebtedness received by the Seller from the Customer, notice of presentment, notice of adverse facts, protest or notice of protest; and (e) notice of any defaults by or disputes with the Customer. This Guaranty shall not be affected by the taking of any checks, notes or other obligations, secured or unsecured, in any amount, purportedly in payment of the whole or any part of any Obligations or by reason of any extension of time given to, or any indulgences shown to, the Customer by the Seller, or by the making, execution and delivery of any oral or written agreement or agreements affecting said Obligations. The Guarantor's liability hereunder shall not be impaired or discharged by reason of any reorganization, insolvency, bankruptcy or similar proceeding (whether voluntary or involuntary) modifying the Seller's rights and remedies against the Customer with regard to any Obligation or liability of the Customer to the Seller under the Sales Agreement. The Guarantor also waives diligence, presentment, protest to or upon Customer with respect to the Obligations. This Guaranty shall be construed as a continuing, absolute and unconditional guarantee of payment without regard to (a) the validity, regularity or enforceability of the Sales Agreement, any of the Obligations or any other collateral security therefor or guarantee a right of offset with respect thereto at any time or from time to time by Seller, (b) until Seller shall have been paid in full, any right by Guarantor to subrogation of indemnification, or (c) any other circumstance whatsoever (with or without notice to or knowledge of the Seller or Guarantor) which constitutes, or might be construed to constitute, an equitable or legal discharge of the Customer for the Obligations, or of Guarantor under this Guaranty, in bankruptcy or in any other instance. When pursuing its rights and remedies hereunder against Guarantor, the Seller may, but shall be under no obligation to, pursue such rights and remedies as it may have against Customer or any other party or against any collateral security or guarantee for the Obligations or any right to offset with respect thereto, and any failure by Seller to pursue such other rights or remedies or to collect any payments from the Customer or any such other party or to realize upon any such collateral security or guarantee or to exercise any such right of offset, or any release of Customer or any such other party or of any such collateral security, guarantee or right of offset, shall not relieve Guarantor of any liability hereunder, and shall not impair or affect the rights and remedies, whether express, implied or available as a matter of law, of Seller against Guarantor. Notwithstanding anything else in this Guaranty to the contrary, Guarantor shall be permitted and entitled to raise all defenses to payment hereunder that are available to Company, other than those defenses available to the Company solely as a result of bankruptcy, insolvency, reorganization and other similar proceedings. This Guaranty shall bind the Guarantor for any and all of the Customer's purchases of natural gas from the Seller, or the Seller's production affiliates, Resource Energy, Inc., Viking Resources Corporation, and Atlas Energy Group, Inc. This Guaranty shall remain in full force and effect and be binding in accordance with and to the extent of its terms upon Guarantor and its successors and assigns thereof, and shall inure to the benefits of the Seller, and its respective successors, transferees, affiliates and assigns, until all Obligations and the obligations of Guarantor under this Guaranty shall been satisfied by payment in full. The Guarantor represents and warrants, as the date hereof, that this Guaranty has been duly authorized, executed and delivered by the Guarantor. 2 This Guaranty shall not be assigned or modified without the written consent of each of the Guarantor and the Seller and shall not be affected by any change in the relationship between Guarantor and the Customer. This Guaranty shall not be relied upon, or enforced, by any person other than the Guarantor, the Customer, and the Seller. This Guaranty shall be governed by and construed in accordance with the laws of the State of Ohio, without regard to the conflict of law rules thereof. The Guarantor and the Seller, by accepting this Guaranty, submit to the non-exclusive jurisdiction of the Courts of the State of Ohio and the United States District Court of Northern District of Ohio. This Guaranty revokes any prior guaranty issued by the Guarantor to the Seller for the obligations of the Customer. IN WITNESS WHEREOF, the Guarantor has caused this Guaranty to be executed by its duly authorized officer as of the date first above written. FIRSTENERGY CORP. Randy Scilla ----------------------- Randy Scilla Assistant Treasurer 3 EX-23.(A) 6 ex23a.txt EXHIBIT 23(A) Exhibit 23(a) CONSENT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS CONSENT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS We have issued our report dated July 21, 2003 on the balance sheet of Atlas America Public #12-2003 Limited Partnership as of July 21, 2003 and our report dated November 22, 2002 on the consolidated financial statements of Atlas Resources, Inc. as of September 30, 2002 contained in the Registration Statement on Form S-1 and Prospectus for Atlas America Public #12-2003 Program. We consent to the use of the aforementioned reports in the Registration Statement and Prospectus, and to the use of our name as it appears under the caption "Experts". /s/ GRANT THORNTON LLP Cleveland, Ohio September 4, 2003 -----END PRIVACY-ENHANCED MESSAGE-----